Petrofac Limited (incorporated in Jersey under the Companies (Jersey) Law 1991 with registered number 81792)

Transcription

1 This document comprises a Prospectus relating to Petrofac Limited prepared in accordance with the Prospectus Rules made by the Financial Services Authority under Part VI Financial Services and Markets Act Application has been made to the Financial Services Authority in its capacity as competent authority under the Financial Services and Markets Act 2000 (the UK Listing Authority ) and to the London Stock Exchange plc (the London Stock Exchange ) for all of the issued ordinary share capital of the Company described in this Prospectus to be admitted to the Official List of the UK Listing Authority (the Official List ) and to trading on the London Stock Exchange. Admission to the Official List together with admission to trading on the London Stock Exchange s main market for listed securities constitute admission to official listing on a regulated market ( Admission ). Conditional dealings in the Ordinary Shares (as unlisted securities) are expected to commence on the London Stock Exchange on 4 October It is expected that Admission will become effective and that unconditional dealings in the Ordinary Shares will commence on 7 October Dealings on the London Stock Exchange before Admission will only be settled if Admission takes place and will be for settlement three business days after Admission. All dealings before the commencement of unconditional dealings will be of no effect if Admission does not take place and such dealings will be at the sole risk of the parties concerned. See Part II Risk factors for a discussion of certain factors that should be considered in connection with an investment in the Ordinary Shares. This Prospectus does not constitute an offer to sell, or the solicitation of an offer to buy, Ordinary Shares in any jurisdiction in which such offer or solicitation is unlawful. The Ordinary Shares have not been and will not be registered under the US Securities Act of 1933, as amended (the Securities Act ) and, subject to certain exceptions may not be offered or sold within the United States or to, or for the account or benefit of, US Persons (as defined in Regulation S under the Securities Act ( Regulation S )). For a description of these and certain further restrictions on offers, sales and transfers of the Ordinary Shares and the distribution of this Prospectus, see Part VIII Details of the Offer. Petrofac Limited (incorporated in Jersey under the Companies (Jersey) Law 1991 with registered number 81792) Offer of up to 152,977,031 Ordinary Shares of US$0.025 each at an Offer Price expected to be between 180 pence and 230 pence per share and admission of 345,159,920 Ordinary Shares to the Official List and to trading on the London Stock Exchange Sponsor and Global Co-ordinator Credit Suisse First Boston Joint Lead Managers and Joint Bookrunners Credit Suisse First Boston Lehman Brothers JPMorgan Cazenove Co-Lead Managers Shuaa Capital Up to 152,977,031 Ordinary Shares are being offered by the Selling Shareholders (as defined herein) in the Offer. The Ordinary Shares are being offered to certain institutional investors in the United Kingdom and the rest of the world excluding the United States by way of the Offer. In connection with the Offer, Credit Suisse First Boston as stabilising manager (the Stabilising Manager ) may over-allot or effect transactions with a view to supporting the market price of the Ordinary Shares at a level higher than that which might otherwise prevail. Such transactions may commence on or after the publication of the Offer Price and will end no later than 30 days thereafter. However, there is no obligation on the Stabilising Manager to do this. Such transactions may be effected on the London Stock Exchange, the over-the-counter market or otherwise. There is no assurance that such transactions will be undertaken and, if commenced, they may be discontinued at any time. Save as required by law, the Stabilising Manager does not intend to disclose the extent of any over-allotments and/or stabilisation transactions under the Offer. In connection with the Offer, certain of the Selling Shareholders have granted the Stabilising Manager an option (the Over-allotment Option ), exercisable for 30 days after publication of the Offer Price, to make available up to 15,297,702 additional Ordinary Shares at the Offer Price to cover over-allotments, if any, made in connection with the Offer and to cover short positions resulting from stabilisation transactions. Share capital immediately following Admission Authorised Issued and fully paid up Number Nominal Value Number Nominal Value 750,000,000 US$18,750,000 Ordinary Shares of US$0.025 each 345,159,920 US$8,628,998 Credit Suisse First Boston and Lehman Brothers, which are authorised and regulated in the United Kingdom by the Financial Services Authority, are advising the Company in relation to the Offer and no one else and will not be responsible to anyone other than the Company for providing the protections afforded to customers of Credit Suisse First Boston or Lehman Brothers respectively nor for providing any advice in relation to the Offer, the contents of this Prospectus or any transaction or arrangement referred to herein.

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3 Any reproduction or distribution of this Prospectus, in whole or in part, and any disclosure of its contents or use of any information herein for any purpose other than considering an investment in the Ordinary Shares offered hereby is prohibited, except to the extent such information is otherwise publicly available. Each person receiving a copy of this Prospectus by accepting delivery of this Prospectus agrees to the foregoing. The distribution of this Prospectus and the offer and sale of the Ordinary Shares in certain jurisdictions may be restricted by law. No action has been taken by the Company, the Selling Shareholders or the Underwriters that would permit a public offer of Ordinary Shares or possession or distribution of this Prospectus where action for that purpose is required, other than in the UK. Persons into whose possession this Prospectus comes should inform themselves about and observe any such restrictions. Any failure to comply with these restrictions may constitute a violation of the securities laws of any such jurisdiction. This Prospectus does not constitute an offer of, or an invitation to purchase, any Ordinary Shares in any jurisdiction in which such offers or invitation would be unlawful. Further information with regard to restrictions on offers and sales of the Ordinary Shares and the distribution of this document is set out in Part VIII Details of the Offer. No person has been authorised to give any information or to make any representation other than those contained in this Prospectus in connection with the Offer and, if given or made, such information or representation must not be relied upon as having been authorised by or on behalf of the Company, the Selling Shareholders or the Underwriters. This Prospectus does not constitute an offer to sell or the solicitation of any offer to buy any securities other than the securities to which it relates or an offer to sell or the solicitation of an offer to buy such securities by any person in any circumstances in which such offer or solicitation is unlawful. Without prejudice to any obligation of the Company to publish a supplementary prospectus pursuant to section 87G Financial Services and Markets Act 2000 and Prospectus Rule 3.4.1, neither the delivery of this Prospectus at any time nor any sale made under this Prospectus shall, under any circumstances, create any implication that there has been no change in the business or affairs of the Company or of the Company and its subsidiaries and affiliates taken as a whole since the date hereof or that the information contained herein is correct as of any time subsequent to its date. The information contained in this Prospectus has been provided by the Company. None of the Underwriters makes any representation, express or implied, or accepts responsibility, with respect to the accuracy or completeness of any of the information in this Prospectus. This Prospectus is not intended to provide the basis of any credit or other evaluation and should not be considered as a recommendation by any of the Company, the Selling Shareholders or the Underwriters that any recipient of this Prospectus should purchase the Ordinary Shares. Each potential purchaser of Ordinary Shares should determine for itself the relevance of the information contained in this Prospectus and its purchase of Ordinary Shares should be based upon such investigation as it deems necessary. A copy of this document has been delivered to the registrar of companies in Jersey in accordance with Article 5 of the Companies (General Provisions) (Jersey) Order 2002, and the registrar has given, and has not withdrawn, consent to its circulation. The Jersey Financial Services Commission has given, and has not withdrawn, its consent under Article 2 of the Control of Borrowing (Jersey) Order 1958 to the issue of securities in the Company. It must be distinctly understood that, in giving these consents, neither the registrar of companies nor the Jersey Financial Services Commission takes any responsibility for the financial soundness of the Company or for the correctness of any statements made, or opinions expressed, with regard to it. The contents of this Prospectus are not to be construed as legal, business or tax advice. Each prospective investor should consult its own solicitor, financial adviser or tax adviser for legal, financial or tax advice. Certain terms used in this document are defined and certain technical and other terms used in this document are explained in Part XI Definitions and Part XII Glossary of industry terms. Unless the context otherwise requires or it is expressly provided to the contrary, the information in this document assumes (a) an Offer Price of 205 pence per Ordinary Share, being the mid point of the Offer Price Range, (b) no exercise of the Over-allotment Option, (c) the re-organisation of the 3

4 Company s share capital (which is conditional upon Admission) having been completed; (d) the allotment and issue of all Ordinary Shares due to be allotted and issued under Petrofac s Long Term Incentive Plan (LTIP), which allotment and issue is conditional upon Admission; and (e) each Selling Shareholder selling his/its full entitlement of Ordinary Shares, including participatory interests in Ordinary Shares held under Petrofac s Executive Share Scheme (ESS) and the LTIP, permitted for sale. All times referred to in this document are, unless otherwise stated, references to London time. CURRENCY AND PRESENTATION OF FINANCIAL INFORMATION Unless otherwise indicated, all references in this document to US$ or US Dollars are to the lawful currency of the United States of America and all references in this document to or Sterling are to the lawful currency of the United Kingdom. The Company prepares its financial statements in US Dollars. Unless otherwise indicated, financial information in this document has been prepared in accordance with International Financial Reporting Standards (IFRS) which differs in certain significant respects from UK GAAP. The Financial Information included in Part X Financial Information on Petrofac has been prepared in accordance with the Statements of Investment Circular Reporting Standards issued by the Auditing Practices Board in the United Kingdom and the related consent to its inclusion in the Prospectus appearing in Part IX Additional Information has been included as required by the Prospectus Rules and solely for that purpose. Accounts are drawn up to each year. The periods analysed in this document are the 12 month periods ended 2002, 2003 and 2004, and such periods are referred to in this document as the 2002 financial year (or FY 2002), 2003 financial year (or FY 2003) and 2004 financial year (or FY 2004), respectively. References to H are to the period from 1 January 2005 to 30 June 2005 and references to H are to the period from 1 January 2004 to 30 June References to H are to the period from 1 July 2005 to 2005 and references to H are to the period from 1 July 2004 to The financial information for H included in this document is unaudited and has been provided as a comparative to the financial information for H This financial information has been prepared using the Group s management accounts on the basis set out in note 2 to section 5 of Part X Financial Information on Petrofac. Financial results included in this document are, unless otherwise stated, results from continuing operations. Unless otherwise stated, basic and diluted earnings per share figures of the Company in this document are calculated by reference to the number of shares, or potential number of shares, prior to the Company s 40:1 share split that has been approved by the Board, conditional upon Admission. Unless otherwise stated, share figures to be sold in the Offer and share figures relating to Selling Shareholders reflect the Company s 40:1 share split that has been approved by the Board, conditional upon Admission. Various figures and percentages set out in this document have been rounded and, accordingly, may not total. Percentage figures of divisional results relative to the Group are, unless otherwise stated, calculated using, as the denominator, Group results after consolidation and elimination adjustments. Unless otherwise stated, the values of the investments of the Resources Division are book equity values. Backlog Petrofac uses the measurement of revenue backlog as a key performance indicator for its Engineering & Construction and Operations Services businesses. Backlog consists of the estimated revenue attributable to the uncompleted portion of lump sum engineering, procurement and construction (EPC) contracts and variation orders plus, with regard to engineering services and facilities management contracts, the estimated revenue attributable to 4

5 the lesser of the remaining term of the contract and, in the case of life of field facilities management contracts, five years. To the extent work advances on these contracts, revenue is recognised and removed from the backlog. Where contracts extend beyond five years, the backlog relating thereto is added to the backlog on a rolling monthly basis. Backlog includes only the revenue attributable to signed contracts for which all pre-conditions to entry have been met and only the proportionate share of joint venture contracts that is attributable to Petrofac. Backlog does not include any revenue expected to arise from contracts where the client has no commitment to draw upon services from the Company. With regard to certain of the Group s facilities management contracts, a substantial proportion of the revenue estimated to arise is subject to the level of capital and operational expenditure determined ultimately by the client. The actual revenue realised on such contracts may therefore differ from that originally estimated in calculating backlog. In addition, the backlog in relation to such contracts may differ from the values ascribed to such contracts by Petrofac at the time of contract award. In relation to such contracts, the backlog figure reflects, at any point in time, the Directors best estimate of the future level of expenditure and hence revenue expected to arise over the remaining term of the contract. In addition, a significant proportion of the Group s revenue is denominated in Sterling. The backlog figure, reported in US Dollars, includes the Sterling revenue converted into US Dollars at the prevailing period end exchange rate. Subsequent variations in the exchange rate will therefore vary the US Dollar backlog amount although the underlying Sterling backlog will remain unchanged. Backlog is not an audited measure. Other companies in the oil and gas industry may calculate this measure differently. Please also see Part II Risk factors and Part VI Operating and financial review. EBITDA References to EBITDA in this document are to the profit before tax and net finance costs and before depreciation, goodwill and other amortisation and impairment losses. References to EBITDA margin are to EBITDA as a percentage of revenues from continuing operations. The Directors use EBITDA internally as an important supplemental measure of Petrofac s operational performance and believe it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in the oil and gas industry. EBITDA has its own limitations as an analytical tool and it should not be considered in isolation from, or as a substitute for, analysis of Petrofac s results of operations, as reported under IFRS. Some of the limitations of EBITDA as a measure are as follows: it does not reflect finance charges, or the cash requirements necessary to service interest or principal repayments, on Petrofac s debt; it does not reflect finance income arising from Petrofac s cash balances; it does not reflect taxes; although depreciation, goodwill and other amortisation are non-cash charges, the tangible or intangible assets being depreciated, amortised or impaired will often have to be replaced in the future; and other companies in the oil and gas industry may calculate this measure differently, limiting its usefulness as a comparative measure. FORWARD-LOOKING STATEMENTS This document includes forward-looking statements which include all statements other than statements of historical facts, including, without limitation, those regarding the Group s financial position, business strategy, plans and objectives of management for future operations (including development plans and objectives relating to the Group s products and services), or any statements preceded by, followed by or that include the words targets, believes, expects, aims, intends, will, may, anticipates, would, could or similar expressions or the negative 5

6 thereof. Such forward-looking statements involve known and unknown risks, uncertainties and other important factors beyond the Group s control that could cause the actual results, performance or achievements of the Group to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. Such forward-looking statements are based on numerous assumptions regarding the Group s present and future business strategies and the environment in which the Group will operate in the future. Among the important factors that could cause the Group s actual results, performance or achievements to differ materially from those in forward-looking statements are those in Part II Risk factors, Part VI Operating and financial review, and elsewhere in the document. These forward-looking statements speak only as at the date of this document. The Company expressly disclaims any obligation or undertaking to disseminate any updates or revisions to any forward-looking statements contained herein to reflect any change in the Group s expectations with regard thereto or any change in events, conditions or circumstances on which any such statements are based unless required to do so by applicable law or the Prospectus Rules, Disclosure Rules or Listing Rules. 6

7 TABLE OF CONTENTS Page Directors, secretary, registered office and advisers 9 Offer statistics and expected timetable of principal events 10 PART I Summary 11 PART II Risk factors 17 PART III Information on the Petrofac Group Overview History Business strategy Description of the business Health, safety and the environment (HSE) and security Risk management Employee Share Schemes Dividend policy 63 PART IV Directors and Senior Managers Board members Other divisional chief executives Senior Managers Corporate governance Directors and Senior Managers interests in Ordinary Shares 70 PART V Selected financial information on Petrofac 72 PART VI Operating and financial review Overview Background Recognition of revenues and profit and timing of cash flows Consolidation of joint ventures Accounting treatment of foreign currencies Backlog Review of the financial results of the Petrofac Group Review of the financial results of Engineering & Construction Review of the financial results of Operations Services Review of the financial results of Resources Discontinued operations Liquidity and cash resources Ratio analysis Capitalisation and indebtedness Treasury management Working capital Current trading and prospects 108 7

8 Page PART VII Competent person s report by Ryder Scott 109 PART VIII Details of the Offer Summary of the Offer Over-allotment and stabilisation Underwriting Agreement Dealing arrangements CREST Lock-in arrangements Provisions governing sales 113 PART IX Additional Information Responsibility The Company Share capital Summary of the Memorandum and the New Articles Employee Share Schemes Directors and Senior Managers Directors and Senior Managers emoluments Major Shareholders Selling Shareholders Related party transactions Taxation Legal and arbitration proceedings Underwriting arrangements Material contracts Subsidiaries and joint ventures Property, plant and equipment Research and development Intellectual property No significant change Miscellaneous Documents on display 149 PART X Financial Information on Petrofac 150 PART XI Definitions 210 PART XII Glossary of industry terms 214 8

9 DIRECTORS, SECRETARY, REGISTERED OFFICE AND ADVISERS Directors Rodney Chase, Non-Executive Chairman Michael Press, Non-Executive, Senior Independent Director Kjell Almskog, Non-Executive Bernard de Combret, Non-Executive Ayman Asfari, Group Chief Executive Keith Roberts, Chief Financial Officer Maroun Semaan, Chief Executive Engineering & Construction all of Whiteley Chambers, Don Street, St Helier, Jersey LE4 9WG As to English Law Norton Rose Kempson House Camomile Street London EC3A 7AN Credit Suisse First Boston 1 Cabot Square London E14 4QJ JPMorgan Cazenove 20 Moorgate London EC2R 6DA Company Secretary and registered office Ogier Secretaries (Jersey) Limited Whiteley Chambers Don Street St Helier Jersey JE4 9WG Legal advisers to the Company Sponsor and Global Co-ordinator Credit Suisse First Boston 1 Cabot Square London E14 4QJ Joint Lead Managers and Joint Bookrunners 9 As to Jersey Law Ogier & Le Masurier Whiteley Chambers Don Street, St Helier Jersey JE4 9WG Lehman Brothers 25 Bank Street London E14 5LE Co-Lead Managers Shuaa Capital Level 28 Emirates Towers Sheikh Zayed Road Dubai, United Arab Emirates Legal Advisers to the Managers Linklaters One Silk Street London EC2Y 8HQ Auditors and Reporting Accountants Ernst & Young LLP 1 More London Place London SE1 2AF Registrars Capita IRG (Offshore) Limited Victoria Chambers Liberation Square 1/3 The Esplanade St. Helier, Jersey JE4 0FF

10 OFFER STATISTICS AND EXPECTED TIMETABLE OF PRINCIPAL EVENTS Offer statistics Offer Price Range (1) 180 to 230 pence Number of Ordinary Shares in the Offer, (to be sold by the Selling Shareholders) Up to 152,977,031 Number of Ordinary Shares subject to the Over-allotment Option Up to 15,297,702 Expected market capitalisation following the Offer (2) million Expected timetable of principal events Event 2005 Announcement of Offer Price and allocation (1) Tuesday, 4 October Publication of pricing statement containing the Offer Price and number of Ordinary Shares in the Offer Commencement of conditional dealings (in unlisted securities) on the London Stock Exchange (3) Admission and commencement of unconditional dealings on the London Stock Exchange CREST accounts credited Where applicable, definitive share certificates despatched by post on or as soon as practicable after Tuesday, 4 October 8.00 a.m. on Tuesday, 4 October 8.00 a.m. on Friday, 7 October 8.00 a.m. on Friday, 7 October Tuesday, 18 October Each of the times and dates in the above timetable is subject to change. (1) It is currently expected that the Offer Price will be within the Offer Price Range, although it may be set above or below this range. (2) Assumes the mid-point of the Offer Price Range. (3) It should be noted that, if Admission does not occur, all conditional dealings will be in unlisted securities and will be of no effect. Any such dealings will be at the sole risk of the parties concerned. 10

11 PART I Summary Any decision by a prospective investor to invest in the Ordinary Shares should be based on consideration of the document as a whole and not solely on this summarised information. Following the implementation of the relevant provisions of the Prospectus Directive (Directive 2003/71/EC) in each member state of the European Economic Area (EEA), civil liability will attach to the Directors in any such member state for this summary, including any translation hereof, but only if this summary is misleading, inaccurate or inconsistent when read together with the other parts of this document. Where a claim relating to the information contained in this document is brought before a court in an EEA state, the claimant may, under the national legislation of the EEA state in which the claim is brought, be required to bear the cost of translating this document before legal proceedings are initiated. 1. Information on Petrofac Petrofac is a leading international provider of facilities solutions to the oil and gas production and processing industry, with a diverse client portfolio which includes many of the world s leading integrated, independent and national oil and gas companies. Through its three divisions, Engineering & Construction (E&C), Operations Services (OS) and Resources, Petrofac designs and builds oil and gas facilities; operates, maintains or manages facilities and trains personnel; and, where return criteria are met and revenue synergies identified, co-invests with clients and partners. Petrofac s range of services allows it to help meet its clients needs across the life cycle of oil and gas assets. Petrofac operates out of four strategically placed international centres in Aberdeen, Scotland; Sharjah, UAE; Mumbai, India; and Woking, England, and has a further 13 offices worldwide, with approximately 5,500 employees. In FY 2004, Petrofac s total revenue from continuing operations was US$951.5 million, with a net profit attributable to Petrofac shareholders of US$46.1 million. In H1 2005, Petrofac s total revenue from continuing operations was US$692.4 million, with a net profit attributable to Petrofac shareholders of US$36.4 million. At 30 June 2005, Petrofac s backlog was US$2.5 billion. Petrofac s business is focused on the UK Continental Shelf (UKCS), the Middle East, North Africa and the Former Soviet Union (FSU) and developed out of a US based engineering, procurement and fabrication business founded in 1981 and disposed of in Through both organic growth and strategic acquisitions, Petrofac s engineering, procurement and construction activities have been complemented with development planning and early stage engineering services, facilities management, training and co-investment. Engineering & Construction (E&C) Division The E&C Division provides services to oil and gas industry clients to develop, design and construct facilities, including: integrated engineering, procurement and construction (EPC) services, including project management, engineering, procurement services and the construction management and commissioning of oil and gas facilities; and specialist engineering and consultancy services, including preparation of field development plans and associated studies, design development, front end engineering and design (FEED), de-manning and decommissioning studies, and the provision of risk, safety and environmental consultancy services. In FY 2004, the E&C Division s external revenue was US$467.1 million with net profit of US$33.1 million, representing approximately 49 and 72 per cent. respectively of the Group for that period. In H1 2005, the E&C Division s external revenue was US$390.2 million with net profit of US$23.0 million, representing approximately 56 and 63 per cent. respectively of the Group for that period. The Directors believe the competitive strengths of the E&C Division include its: disciplined project evaluation and selection; 11

12 proven in-house expertise in engineering design and project execution; proven project execution capability in challenging and geographically remote areas; established client relationships with both international and national oil companies; access to high calibre engineering personnel from low cost countries; and established local relationships with partners and sub-contractors. Operations Services (OS) Division The OS Division provides services to oil and gas industry clients to operate, maintain and modify facilities and train personnel, including: facilities operations and maintenance services for onshore and offshore installations, including the provision of operations management, maintenance services and consultancy, brownfield engineering services and specialist manpower; and specialist training and human resource development, including: safety training; operations and technical training; emergency response and critical incident management training; and training support and management services. In FY 2004, the OS Division s external revenue was US$439.4 million with net profit of US$9.6 million, representing approximately 46 and 21 per cent. respectively of the Group for that period. In H1 2005, the OS Division s external revenue was US$279.6 million with net profit of US$7.3 million, representing approximately 40 and 20 per cent. respectively of the Group for that period. The Directors believe the competitive strengths of the OS Division include its: leading position as an independent provider of turnkey facilities management in the UKCS; established track record of facilities performance improvement; range of specialist and value-added services; strong safety track record; and highly regarded training businesses in practical fire-fighting, survival training, technical training and emergency response training. Resources Division In selected situations, the Resources Division invests alongside its clients and partners in producing and proven or probable but not fully developed oil and gas reserves and energy infrastructure. Investments are assessed on the basis of their projected financial return reflecting the anticipated risks of the investment and, independently, the opportunity for the Group to provide services to its clients and partners. In FY 2004, the Resources Division s external revenue was US$45.0 million with net profit of US$7.0 million, representing approximately 5 and 15 per cent. respectively of the Group for that period. In H1 2005, the Resources Division s external revenue was US$22.6 million with net profit of US$12.0 million, representing approximately 3 and 33 per cent. respectively of the Group for that period. As at 30 June 2005, the Group s investments had a book value of US$96.6 million. The Directors believe the competitive strengths of the Resources Division include its: experienced and high calibre project development team; ability to draw on client relationships, know-how and service expertise within the wider Group to enhance identification, evaluation and completion of investments; ability to share high level business contacts established by the Resources Division to create new business opportunities for the wider Group; and track record in challenging countries. 12

13 2. Industry Conditions As a provider of services to the oil and gas industry, Petrofac s revenues are driven by three broad factors: (i) the level of capital expenditure of the oil and gas industry to develop proven and probable hydrocarbons and construct related hydrocarbon processing, transportation and refining facilities; (ii) the level of operations outsourcing by oil and gas companies; and (iii) the industry-wide requirements for trained personnel. In turn, these three factors are affected by current and expected oil and gas prices. According to the BP Statistical Review of World Energy June 2005, there is limited excess production capacity relative to demand and, since 2004, this has led to significant increases in current and expected oil and gas prices. The additional supply necessary to match the expected increase in demand is likely to require an increased level of spending across the life cycle of oil and gas production assets. Three ongoing trends are affecting the structure of the oil and gas industry. First, during the 1990s, oil and gas companies adjusted their business models to focus on reservoir identification and management, and activities such as project and facilities management have subsequently been increasingly outsourced. Second, there has been a trend for major integrated oil companies to divest their more mature and smaller-scale fields to independent E&P companies. This trend has been evident in the UKCS, where Petrofac is a significant provider of facilities management services through its OS Division. Third, although the national oil companies have historically relied upon major integrated or independent companies to operate and manage their fields through concession or licence agreements, they are increasingly seeking to develop their reserves and operate their production processes themselves. As hydrocarbon reserves in OECD countries become increasingly depleted, the remaining concentration of hydrocarbon reserves is shifting to non-oecd regions such as the Middle East, Caspian, North Africa, and West Africa, where hydrocarbon reserves are typically controlled by national oil companies. The national oil companies are therefore awarding an increasing proportion of construction and facilities maintenance contracts. The Directors believe that Petrofac s service offerings and existing customer relationships with the independent E&P companies and national oil companies position it to benefit from each of these trends. 3. Business strategy The Directors goal is to generate sustainable growth in value for Petrofac s shareholders by being a leading international provider of facilities solutions to the oil and gas industry, delivering world-class project development, project management, engineering, procurement, construction, operations and training services. The Directors aim to achieve this goal by: leveraging client relationships by providing a range of services across the life cycle of an asset; focusing on regions with major hydrocarbon reserves where significant capital and operational expenditures are expected; expanding the Group s established service offering into new countries; assisting clients in achieving their local content goals by increasing the use of indigenous resources and improving the competence of local workforces; improving revenue and earnings stability through a diversified and complementary business model; attracting and retaining recognised specialists and key personnel; maintaining and improving on high safety standards; and identifying, acquiring, integrating and developing complementary businesses, where appropriate. 4. Risk factors Risks attaching to an investment in Petrofac include the following: Business risks Demand for the Group s services is linked to the level of expenditure by the oil and gas industry, which is not easy to predict. 13

14 The trend for owners of oil and gas installations to outsource management of those installations may not continue or may be reversed. The Group may not accurately estimate the costs of, or execute within budget, its lump sum contracts or may fail to complete contracts on time. The Group may be affected by the actions of third parties, including sub-contractors, manufacturers and partners. The Group is subject to counterparty credit risk. The investments made by the Group s Resources Division may not generate profit or business synergies and may decline in value. The Group is dependent on a relatively small number of contracts at any given time. The Group s revenues, cash flow and earnings may vary in any period depending on a number of factors, including its performance of major contracts. The Group s future business performance depends on the award of new contracts and renewals and extensions of existing contracts. The Group s long term contracts may be subject to early termination, variation or non-renewal. The Group has significant international operations, particularly in the Middle East, North Africa and the FSU, which are susceptible to political, social and economic instability. The Group is subject to the complexity of running a business with a wide geographic spread. The Group is exposed to foreign exchange risk. Consolidation among oil and gas companies may result in fewer potential clients for the Group or in termination of existing contracts. Competition in the Group s industries could result in reduced profitability and loss of clients. The Group may encounter difficulties integrating future acquisitions. Intellectual property infringement could adversely affect the financial performance of the Group. Petrofac may not be able to manage its growth effectively. Human resources risks The Group may be unable to attract and retain sufficient skilled personnel to meet its operational requirements. The change in ownership resulting from the Offer may have an adverse effect on the Group s ability to retain or incentivise its Directors and Senior Managers. The Group is dependent on its senior personnel. Work stoppages and other labour problems could adversely affect the Group. Liability risks The Group could be subject to substantial liability claims due to the hazardous nature of its business. The Group conducts its business within strict environmental regimes and may be exposed to potential liabilities and increased compliance costs. The Group conducts its operations within strict health and safety regimes, particularly in the UKCS. Failure to comply with the relevant regulations could adversely affect its reputation and future revenues. The Group s businesses may be subject to claims for professional errors and omissions. Liability to clients under warranties may materially and adversely affect the Group s earnings. The Group is, and may continue to be, involved in litigation. 14

15 Damage to the Group s reputation and business relationships may have an adverse effect beyond any monetary liability arising. Taxation risks Changes in certain fiscal regimes could adversely impact the financial condition of the Group. If the Company were deemed to be resident for taxation purposes outside Jersey, this could have adverse taxation implications. Risks relating to the Ordinary Shares Because the Company is a holding company it is financially dependent on receiving distributions from its subsidiaries. If the Company becomes a controlled foreign company for UK taxation purposes, a UK resident holder of 25 per cent. or more of the Ordinary Shares would be exposed to a tax risk. The Group s reporting currency is different to the currency in which dividends will be paid. Investors may not be able to resell their Ordinary Shares at or above the Offer Price. The availability of Ordinary Shares for future sale could depress the share price. 5. Summary financial information The table below sets out Petrofac s summary financial information for the periods indicated. Summary Consolidated Income Statement 6 months ended 30 June 2005 Unaudited 6 months ended 30 June 2004 Year ended 2004 Year ended 2003 Year ended 2002 Continuing operations Engineering & Construction 390, , , , ,781 Operations Services 279, , , ,372 12,703 Resources 22,572 21,569 45,042 14,439 13,914 Revenue 692, , , , ,398 Profit from continuing operations before tax and finance costs 41,081 32,453 68,283 37,747 35,296 Profit for the period from continuing operations 36,392 21,948 46,037 35,195 34,022 Discontinued operations Loss for the period from discontinued operation (202) (12,942) (13,162) (16,241) (12,268) Profit for the period 36,190 9,006 32,875 18,954 21,754 Attributable to: Petrofac shareholders 36,190 9,052 32,921 22,118 22,068 Minority interests (46) (46) (3,164) (314) 36,190 9,006 32,875 18,954 21,754 Continuing operations EBITDA 54,346 45,143 96,065 48,075 39,043 15

16 Selected Balance Sheet Items 30 June Property, plant and equipment (net book value) 123, , ,395 93,268 Trade and other receivables 209, ,042 96,485 88,238 Cash and short term deposits 141, ,534 97, ,524 Total assets 749, , , ,643 Total equity 133, , ,394 96,102 Trade and other payables 100, , , ,021 Total debt (1) 155, , ,593 87,116 Total equity and liabilities 749, , , ,643 (1) Total debt comprises current and non current interest-bearing loans and borrowings and also includes US$37.7 million of A ordinary shares which, immediately prior to Admission, will be converted into ordinary shares and consequently reclassified as equity. 6. Summary of the Offer The Offer comprises an offer of up to 152,977,031 Ordinary Shares by the Selling Shareholders. The Ordinary Shares are being offered to certain institutional investors in the United Kingdom and the rest of the world (excluding the United States). The Over-allotment Shareholders have granted the Stabilising Manager, on behalf of the Underwriters, the Over-allotment Option, exercisable for a period of up to 30 days after publication of the Offer Price, over Ordinary Shares representing up to 10 per cent. of the Ordinary Shares in the Offer at the Offer Price to cover any over-allotments made in connection with the Offer and to cover short positions resulting from stabilisation transactions. Under the Offer, all Ordinary Shares will be sold at the Offer Price, which will be determined by the Joint Lead Managers following consultation with the Company, and is expected to be announced on 4 October Admission and unconditional dealings in the Ordinary Shares are expected to commence on the London Stock Exchange on 7 October Prior to that time, it is expected that dealings in the Ordinary Shares will commence on a conditional basis on the London Stock Exchange on 4 October These dates may change. Dealings on the London Stock Exchange before Admission will only be settled if Admission takes place and will be for settlement three business days after Admission. All dealings before the commencement of unconditional dealings will be in unlisted securities, of no effect if Admission does not take place and at the sole risk of the parties concerned. 7. Management Directors and Senior Managers The Company s Directors are: Rodney Chase, Non-Executive Chairman Michael Press, Non-Executive, Senior Independent Director Kjell Almskog, Non-Executive Bernard de Combret, Non-Executive Ayman Asfari, Group Chief Executive Keith Roberts, Chief Financial Officer Maroun Semaan, Chief Executive Engineering & Construction The Board is supported by divisional chief executives, Amjad Bseisu and Robin Pinchbeck, and a further 16 Senior Managers. Lock-in arrangements The New Articles will contain provisions governing the transfer of Ordinary Shares by certain employee Shareholders. In addition, the Company and certain Selling Shareholders and members of senior management have agreed not (without the Joint Lead Managers prior consent) to issue, sell, grant options over or otherwise dispose of Ordinary Shares for designated lock-in periods. 16

17 PART II Risk factors Any investment in the Ordinary Shares is subject to a number of risks. Before making any investment decision, prospective investors should carefully consider the factors and risks attaching to an investment in the Ordinary Shares, together with all other information contained in this document including, in particular, the risk factors described below. The information below does not purport to be exhaustive. Additional risks and uncertainties not presently known to the Group, or that the Group currently deems immaterial, may also have an adverse effect on its business. Investors should consider carefully whether an investment in the Ordinary Shares is suitable for them in light of the information in this document and their personal circumstances. Business risks Demand for the Group s services is linked to the level of expenditure by the oil and gas industry, which is not easy to predict. Demand for the majority of the Group s oil and gas services is dependent on expenditure by the oil and gas industry for the exploration, development and production of crude oil and natural gas reserves. Lower expenditure by the oil and gas industry may result in lower demand for the Group s services, which would adversely affect the Group s financial performance and condition. Demand for the Group s services may be influenced by cyclical patterns in the wider oil and gas industry. In particular, the Group s Resources Division, which has investments in producing fields, is potentially exposed to fluctuations in oil and gas prices, while the Group s Operations Services (OS) Division and Engineering & Construction (E&C) Division may also be indirectly affected by such changes. The diversity of the Group s operations may not protect the Group against such fluctuations in demand. Increases in oil and gas prices may not result in an increase in demand for the Group s services. On the other hand, a substantial or extended decline in oil or gas prices would be likely to cause a decline in the demand for the Group s services. The trend for owners of oil and gas installations to outsource the management of those installations may not continue or may be reversed. The Directors believe that asset owners are increasingly outsourcing the management of their onshore and offshore assets. If this outsourcing trend does not continue (in particular, outside the UKCS), or is reversed, the number of potential clients of the Group may be reduced. In addition, the Group may lose existing clients if this trend reverses. The Group may also lose employees (who could have been retained and redeployed elsewhere) if owners of facilities with the management outsourced to Petrofac choose to take management of such facilities and, accordingly, the relevant employees, in-house. Reductions in oil prices to levels that reduce the economic life of fields or result in reduced divestiture activity by major oil companies (which have been traditional users of outsourced management) may lead to less demand for the Group s services. A reduction in demand for the Group s services due to a shift in this outsourcing trend may have a material adverse effect on the Group s future financial performance and condition. The Group may not accurately estimate the costs of, or execute within budget, its lump sum contracts or may fail to complete contracts on time. Under the Group s lump sum contracts (including its major engineering, procurement and construction (EPC) contracts), the Group performs its services and provides its products at a fixed price. If the Group s cost estimate for a contract is inaccurate, or if the Group does not execute the contract within its cost estimates, cost overruns may cause the project to be less profitable than expected or cause the Group to incur losses. The Group s EPC projects generally involve complex design and engineering, significant procurement of equipment and supplies, and extensive construction management. Many projects are ongoing for extended time periods, often in excess of two years, from initial award through to completion. During this time the Group may encounter difficulties in the design or engineering of 17

18 the project or in equipment and supply delivery, schedule changes or other disruption (such as political or local community unrest or prolonged adverse weather conditions), some of which may be beyond its control, and any of which may impact its ability to complete the project within budget or in accordance with the original delivery schedule. Delays in completion of a lump sum project or failure to meet certain Key Performance Indicators (KPIs) may in certain circumstances also expose the Group to liquidated damages, which may have an adverse effect on the Group s financial performance. The Group may be affected by the actions of third parties, including sub-contractors, manufacturers and partners. The Group relies on third-party equipment manufacturers and sub-contractors in the completion of its projects. To the extent that the Group cannot engage sub-contractors or acquire equipment or materials according to its plans and budgets, its ability to complete an EPC project in a timely fashion or at a profit may be impaired. If the amount the Group is required to pay for these goods and services exceeds the amount estimated in bidding for fixed price work, the Group could experience losses under the relevant contracts. In addition, if a sub-contractor or a manufacturer is unable to deliver its services, equipment or materials according to the negotiated terms or on time, the Group may be required to purchase such services, equipment or materials from another source at a higher price. The resulting additional costs may be substantial, and the Group may be required to compensate the project client for delays. The Group may not be able to recover all of these costs in all circumstances, which may reduce the profit to be realised or result in a loss on a project for which the services, equipment or materials were needed. The Group may bid for a particular contract jointly with a consortium or joint venture partners. In these circumstances, the Group s ability to maximise the profitability of any contract awarded to it may be adversely affected by the performance of its consortium or joint venture partners. In addition, the Group may be dependent on the expertise of partners in assessing certain of the costs of the contract. To the extent such costs are inaccurately calculated in relation to lump sum contracts, the Group may be exposed to its share of any cost overruns of the consortium or joint venture, which could have a material adverse effect on the financial performance of the Group. In certain circumstances, the Group may be jointly and severally liable for the acts or omissions of its consortium or joint venture partners. This may arise under the terms of the consortium or joint venture arrangement or because the Group is exposed to the losses of any consortium or joint venture vehicle. In addition, the Group may in certain circumstances accept primary liability by way of a separate guarantee for the overall performance of the contract where it is only providing part of the goods or services to the client. If a client pursued claims against the Group or against a consortium or joint venture vehicle as a result of the acts or omissions of the Group s partners, the Group s ability to recover from such partners may be limited. Recovery under such arrangements may involve delay, management time, costs and expenses or may not be possible at all, which could adversely affect the Group s financial performance. The Group is subject to counterparty credit risk. The Group provides its services to a variety of contractual counterparties and is therefore subject to the risk of non-payment for services it has rendered or non-reimbursement of costs it has incurred. The EPC contracts which the Group enters into may require significant expenditure by the Group prior to receipt of relevant payments from the client and expose the Group to potential credit risk. In addition, the Group is active in a number of markets where payment terms are not always met or where its counterparties may take a strict contractual approach to performance of KPIs regardless of the overall success of the project. In these markets, management intervention is often required in order to obtain payment. Petrofac may enter into contracts with a joint venture or consortium representing the various asset owners. Unless appropriate guarantees can be obtained by the Group, the Group is subject to a higher risk of non-payment when its contractual counterparty is a special purpose joint venture or consortium vehicle which does not have significant financial resources of its own. 18

19 Failure by any of its contractual counterparties to pay for services provided or reimburse costs incurred by the Group could have a material adverse effect on the Group s cashflow and on the profitability of the relevant contract for the Group. This does not qualify the working capital statement made by the Company in Part VI Operating and financial review. The investments made by the Group s Resources Division may not generate profit or business synergies and may decline in value. The Group s Resources Division invests in companies and projects in order to earn an investment return and to secure additional service provision by the Group s E&C and OS Divisions. However, there can be no assurance that any investment will generate the expected return or provide the expected business synergies for the other two divisions of the Group. If the market value of any of the Group s investments declines, the Group may be forced to write down the recorded value of the investment. The Group may also be required to make additional cash investments in the future to fund the operating or capital expenses of its investments. Furthermore, some of the investments are subject to contractual and other restrictions on transfer and the Group may not be able to dispose of them at attractive prices or in a timely manner. The Group s financial performance and condition may be impaired by investments which do not generate profit or business synergies or which decline in value or cannot be remarketed. The Group is dependent on a relatively small number of contracts at any given time. Due to the size of many of its E&C and OS projects, the majority of the Group s revenue in any year may be derived from a relatively small number of contracts. For the 6 months ended 30 June 2005 for example, contracts for five clients represented approximately 90 per cent. of the Group s revenues from its E&C Division and contracts for five clients represented approximately 43 per cent. of the Group s revenues from its OS Division. Consequently, should any one of those contracts prove less profitable for the Group than expected, or be loss making, revenues may decline, which may have a material adverse effect on the Group s financial performance and condition. In addition, the Group may have multiple projects for the same client; therefore one client may comprise a significant percentage of the Group s backlog. Part of the Group s strategy is to bid for integrated projects, which involve several different parts of the Group and to leverage existing relationships to offer services from its other divisions. In the event that this strategy results in the Group s portfolio becoming more concentrated on fewer contracts or fewer clients, its exposure to individual contract risks will increase. Loss of a contract for a client of more than one division of the Group or worse than expected performance under such a contract may have a knock-on impact on contracts for the same client in the other divisions, and may thereby have a correspondingly more significant adverse effect on the Group s financial performance and condition. The Group s revenues, cash flow and earnings may vary in any period depending on a number of factors, including its performance on major contracts. The Group s revenues from its lump sum contracts are recognised using the percentage-of-completion (POC) method of accounting. This involves the Group recognising an increasing proportion of contract revenues and earnings as the contract progresses towards 100 per cent. completion. The revenues and earnings (or losses) are based on estimates of contract revenues, costs and profitability and may not reflect actual revenues, earnings or losses for the contract. In addition, although revenue and earnings may be recognised, these do not represent cash received by the Group and accordingly there will be a difference between the Group s revenues and cashflows for any particular reporting period. Cancellations of projects or delays in completion of contracts could affect the revenue, cash flow and earnings actually received from contracts reflected in the Group s backlog, and in certain circumstances may result in a reduction, reversal or elimination of previously reported revenues or earnings. Accordingly there can be no assurance that the revenues projected in the Group s backlog will be realised. In the event of project cancellation, the Group may have no contractual right to the total revenues reflected in its backlog other than reimbursement for certain costs. If the Group were 19

20 to experience significant cancellations or delays of projects in its backlog, its financial performance and condition would be adversely affected. This does not qualify the working capital statement made by the Company in Part VI Operating and financial review. The Group s future business performance depends on the award of new contracts and renewals and extensions of existing contracts. A substantial portion of the Group s revenues is directly or indirectly derived from large-scale projects. It is generally very difficult to predict whether and when the Group will be awarded such contracts as they frequently involve a lengthy and complex bidding and selection process. This process is affected by a number of factors, such as market conditions, financing arrangements and governmental approvals. In addition, many of these contracts are subject to financing contingencies and, as a result, the Group is subject to the risk that it or the client will not be able to secure the necessary financing for the project. The bidding costs associated with tendering for new contracts or for extensions in the scope of work or renewals of existing contracts can be significant and may not necessarily result in the award of a new contract, or in the extension or renewal of an existing contract. These costs are usually not recoverable even if the tender is won. The Group participates in a number of such tenders each year. Failure to win such tenders may adversely affect the Group s future financial performance. In addition, preparation of bids can divert significant management and operating resources away from the day-to-day running of the business. The Group s long term contracts may be subject to early termination, variation or non-renewal. Certain of the contracts entered into by members of the Group are long term contracts, which are performed over a period that often exceed two years. Any of the Group s contracts may be terminated earlier than expected, either within the relevant notice periods or upon default or non-performance by the contracting Group member. In such circumstances the Group may not have the right to receive compensation in respect of such early termination. Certain of the long term contracts of the Group s OS Division give clients the right to terminate at any time on short notice with little or no penalty. In addition, failure to meet certain milestones under a Field Development Plan (FDP) relating to investments of the Resources Division may lead to other adverse effects including, for example, loss of a licence. Termination rights may also arise as a result of a change of control of the Company or a change in the level of holdings in the Company s issued share capital. In particular, the Ohanet Consortium (in which the Group has a 10 per cent. interest) operates subject to certain provisions of Algerian law, which regulate the direct or indirect ownership by foreign companies of interests in Algerian partnerships for the prospection, research and exploitation of liquid hydrocarbons, and which can, in certain circumstances (including a change of control or a third party acquiring a determining power in the direction or management of the Company, for example, by acquiring a holding in excess of 10 per cent. or the power to decide on the composition of the Board) give rise to a right of termination. As detailed in the paragraph headed Ohanet, Algeria in section 4 of Part III Information on the Petrofac Group, it is not envisaged that the Offer will give rise to such a right of termination. However there can be no assurance that changes in ownership of the issued share capital of the Company, including as a result of the Offer, will not give rise to such termination rights arising in relation to the Ohanet Consortium in the future. In addition, certain of the Group s contracts, particularly for the OS Division, are subject to renewal at intervals. There can be no assurance that such contracts will be renewed and, if renewed, that the renewal will be on the same terms. The early termination or non-renewal of contracts would have an adverse impact on the Group s financial performance and condition as they may not be replaced by new contracts. The Group s contracts may also be subject to variation by renegotiation or by requiring the Group to provide a different level of service, which may result in reduced profitability or losses for the Group. 20

21 The Group has significant international operations, particularly in the Middle East, North Africa and the Former Soviet Union (FSU), which are susceptible to political, social and economic instability. The Group s international operations, particularly those in the Middle East, North Africa and the FSU, may be susceptible to political, social and economic instability and civil disturbances. Risks for the Group in operating in such areas include: difficulties in collecting accounts receivable and longer collection times than in the UK; disruption to operations, including strikes, civil actions or political interference; restrictions on the movement of funds or limitations on the repatriation of funds; the imposition of sanctions by the UK government, EU Commission, US government or other governments; and limited access to markets for periods of time. Any of the above factors could result in disruptions to the Group s business, increase costs, result in liability for liquidated damages or reduce future growth opportunities. Potential losses caused by these disruptions may not be covered by insurance. The Group is subject to the complexity of running a business with a wide geographic spread. The Group operates its business in a range of international locations and it is expected that the geographical expansion of the Group s business will take it into new locations in the future. The Group currently operates its businesses and markets its services in more than 20 countries. Through its international presence the Group is subject to increased risk from a number of legal, economic and market factors which could have an adverse effect on the ability of the Group to provide services in those areas, or to continue to expand its business geographically. Such risks include: increased expenses due to the requirement in some countries that business be conducted through local agents; reversal of current policies (including favourable tax and lending policies) encouraging foreign investment or foreign trade by the governments of countries in which the Group operates; changes in and difficulties in complying with laws and regulations of different countries, including tax and labour laws; restrictive actions by local governments, including the imposition of tariffs and limitations on imports or exports; nullification, modification or renegotiation of contracts; and expropriation of assets. The occurrence of any of these events could have an adverse effect on the financial performance and condition of the Group and adversely affect the value of its assets. In addition, the geographical spread of the Group s operations means co-ordination of effort and communications with employees are subject to certain challenges, which could lead to inefficient allocation of resources or duplication of effort. Furthermore, distance from the Group s principal locations can make it more difficult to implement and impress upon local workforces the Group s policies on matters such as health and safety and can present challenges in the supervision of the Group s sub-contracted employees. Failure to deliver consistently high standards across all of its fields of operations could create risks for the Group, including reputational risks. 21

22 The Group is exposed to foreign exchange risk. The Group s reporting currency is US Dollars. All of the revenues and costs from the UKCS operations of its OS Division are denominated in Sterling. The US Dollar contribution of the OS Division in the Group s reported results, and to the Group s overall level of backlog, may therefore fluctuate with changes in Sterling/US Dollar exchange rates. From time to time the Group enters into contracts or incurs costs denominated in currencies other than US Dollars or Sterling and may not always be able to match revenues with costs denominated in the same currency. Whilst the Group attempts to minimise its exposure to such foreign exchange risks through measures such as buying the local currencies of its suppliers and vendors forward at the date on which the contract is awarded and by including escalation provisions for projects in inflationary economies, there can be no assurance that the Group will be able to successfully hedge its foreign exchange risks. Consolidation among oil and gas companies may result in fewer potential clients for the Group or in termination of existing contracts. Consolidation among oil and gas companies may result in fewer potential clients for the Group. This may lead to increased competition to secure contracts. Furthermore, mergers and acquisitions may result in the acquisition of a client of the Group by an entity which does not have a policy of outsourcing services or which has established relations with a competitor of the Group. Similarly, a change of control of an asset managed by the Group may lead to the early termination of the Group s facilities management contract in relation to that asset. The termination of any of the Group s facilities management contracts or a reduction in demand for the Group s services as a result of merger and acquisition activity may have a material adverse effect on the Group s financial performance and condition. Competition in the Group s industries could result in reduced profitability and loss of clients. Contracts for the Group s services and products (including the majority of its EPC contracts and certain of its OS contracts) are generally awarded following a competitive process. While service quality, technological capacity and performance and personnel, as well as reputation and experience, are considered in client decisions, price is the major factor in most tender awards. In the past, the Group s industry has been frequently subject to price competition. If price competition were to intensify in the future, the number of tenders meeting the Group s margin criteria could decline and the Group s financial performance could be adversely affected. The Group may encounter difficulties integrating future acquisitions. From time to time, the Group has made acquisitions to pursue market opportunities, increase its existing capabilities or expand into new areas of operation. The Group may make further acquisitions in the future. If such acquisitions are pursued and executed, the Group may encounter difficulties integrating these acquisitions into its business and in successfully realising the growth expected from such acquisitions. To the extent the Group encounters problems in integrating its acquisitions, the Group s financial performance and condition could be adversely affected. The Group s expansion into new business areas may also expose it to additional business risks that are different from those it has experienced to date. Failure to manage such risks successfully may have an adverse effect on the Group s financial performance and condition. Intellectual property infringement could affect the financial performance of the Group. In providing its services the Group uses both know-how which it regards as proprietary and certain intellectual property which it licenses from third parties. The Group has not protected its proprietary know-how by patents or other registered form of intellectual property right protection and, while it seeks to secure appropriate contractual protection, it is possible that third parties may access and utilise this know-how to the detriment of the Group. The Group s business may be adversely affected if it infringes patents or other intellectual property rights held by third parties or if certain licenses are withdrawn or not renewed. 22

23 The Group invests resource in building the goodwill and brand recognition applicable to the names Petrofac, RGIT Montrose and Rubicon. While steps have been commenced to protect the Petrofac name through formal trade and service mark registration or similar legal protection, until this process is complete the Group may have a limited ability in law to prevent third parties from diluting the Group s brand and goodwill in certain markets. The Group uses the RGIT Montrose name under licence. Failure to protect adequately the Group s brand and goodwill may have an adverse effect on the financial performance and condition of the Group. Petrofac may not be able to manage its growth effectively. Petrofac s business and operations have experienced significant growth. Since 2002, Petrofac s total revenue has grown at a compound annual growth rate of 56 per cent. The growth in the Group s business has placed, and is likely to continue to place, significant demands on its operational and financial infrastructure as well as upon management. The Group has upgraded and streamlined its financial and management reporting systems over the last three years, including the implementation of a new consolidation and financial reporting system which was completed in early In addition, the Group has attempted to address personnel resourcing issues that have arisen as a result of its international expansion. If these measures prove ineffective, its financial performance and operating results could be materially and adversely affected. The Group may have to incur further expenditure to address additional operational and financial control requirements and management resources would be required to be committed to their implementation. The Group operates from a number of locations internationally and does not currently have a formalised disaster recovery plan covering all of its locations to ensure the continued operation of core information technology systems and business processes in the event of a serious disruption. The Directors plan to develop a disaster recovery plan for all of the Group s major locations. However if this is not implemented successfully, Petrofac s financial performance and condition could be materially adversely affected. Human resources risks The Group may be unable to attract and retain sufficient skilled personnel to meet its operational requirements. Demand for engineers, production operations personnel and other technical and management personnel is currently high worldwide and supply is limited, particularly in the case of skilled and experienced engineers and field service personnel in Western Europe and the US. This shortage is exacerbated by the ageing of the current skilled workforce which is not being fully replaced by younger entrants, as well as an increasing reluctance of workers from Western Europe and the US to work overseas and by local employment legislation, such as the European Working Time Directive, which may limit the hours and shift patterns that employees in the UKCS can work. This shortage may also be exacerbated where the Group is required by national oil companies to use local workforces, which may not be fully trained. The ability of the Group to meet its operational requirements and the future growth and profitability of the Group may be affected by the scarcity of engineers, production operations personnel and other technical and management personnel or by potential increases in compensation costs associated with attracting and retaining these employees. The change in ownership resulting from the Offer may have an adverse effect on the Group s ability to retain or incentivise its Directors and Senior Managers. At Admission, the Directors and Senior Managers of the Group, together with their connected persons, will own, or have a beneficial interest in, approximately 53 per cent. of the Ordinary Shares. It is expected that following the Offer that group will own, or have a beneficial interest in, up to approximately 39 per cent. of the Ordinary Shares. This change in ownership structure may result in the interests of the Group and its Directors and Senior Managers becoming, or being perceived to be, less aligned. There can be no assurance that the measures put in place by the Group aimed at incentivising and retaining Directors and Senior Managers will be successful. 23

24 The Group is dependent on its senior personnel. The Group depends on the continued services of its senior personnel, including its directors and senior management from time to time. The existing Directors and Senior Managers possess marketing, engineering, project management, financial and administrative skills that are important to the operation of the Group s business. The Group is putting in place succession planning measures aimed at ensuring the development of its employees to provide successors, over time, for the Group s existing Directors and Senior Managers. However, there can be no assurance that these measures will be successful or that the Group will be able to attract, develop or retain executives of the right calibre. The ability of the Group to meet its operational requirements and the future growth and profitability of the Group may be affected by the scarcity of senior management personnel. If the Group lost or suffered an extended interruption in the services of a substantial number of its Directors or Senior Managers, or if it were unable to attract or develop a new generation of senior management, its financial performance and condition could be adversely affected. The Group does not, in all cases, have the benefit of restrictive covenants in relation to its Directors and Senior Managers, and where it does, such restrictive covenants may not be enforceable. Work stoppages and other labour problems could adversely affect the Group. A lengthy strike or other work stoppage at any of the Group s facilities could have a material adverse effect on the Group s ability to conduct its activities and complete its contractual obligations. Some of the UKCS employees of the OS Division are represented by labour unions. From time to time the Group may also experience attempts to unionise its non-union operations, and it may experience additional union activity in the future. In addition, the Group may encounter delays and interruptions caused by industrial action affecting its sub-contractors or suppliers, or by political interference or local community action. Any such delays, stoppages or interruptions could have a material adverse effect on the Group s financial performance and condition. Liability risks The Group could be subject to substantial liability claims due to the hazardous nature of its business. Many of the Group s services are carried out in hazardous environments, such as development and production installations, and the Group engineers and constructs large industrial facilities in which system failure can be disastrous. An accident or a service failure can cause personal injury, loss of life, damage to property, equipment or the environment, consequential losses and suspension of operations. The Group may also be liable for acts and omissions of sub-contractors or joint venture partners which cause such loss or damage. The Group s insurance and its contractual limitations on liability may not adequately protect it against liability for such events, including events involving pollution, or against losses resulting from business interruption. In addition, indemnities which the Group receives from sub-contractors may not be easily enforced if the relevant sub-contractors do not have adequate resources. Moreover, the Group may not be able to maintain insurance at levels that it deems adequate or ensure that every contract contains adequate limitations on liabilities. Any claims made under its insurance policies are likely to cause the Group s premiums to increase. Any future damage caused by the Group s products or services that are not covered by insurance, are in excess of policy limits, are subject to substantial deductibles or are not limited by contractual limitations of liability could adversely affect the financial performance and condition of the Group. The Group conducts its business within a strict environmental regime and may be exposed to potential liabilities and increased compliance costs. The Group is subject to increasingly stringent laws and regulations relating to environmental protection in conducting the majority of its operations, including laws and regulations governing emissions into the air, discharge into waterways, and the generation, storage, handling treatment and disposal of waste materials. The Group incurs, and expects to continue to incur, capital and operating costs to comply with environmental laws and regulations. The technical requirements of 24

25 environmental laws and regulations are becoming increasingly expensive, complex and stringent. These laws may provide for strict liability for damage to natural resources or threats to public health and safety. Strict liability can render a party liable for environmental damage whether or not negligence or fault on the part of that party can be shown. Some environmental laws provide for joint and several strict liability for remediation of spills and releases of hazardous substances. The business of the Group often involves working around and with volatile, toxic and hazardous substances and other highly regulated materials, the improper characterisation, handling or disposal of which could constitute violations of UK or other legislation and result in criminal and civil liabilities. Environmental laws and regulations generally impose limitations and standards for certain pollutants or waste materials and require the Group to obtain permits and comply with various other requirements. Governmental authorities may seek to impose fines or penalties on the Group, or revoke or deny issuance or renewal of operating permits, for failure to comply with applicable laws and regulations. The Group could become subject to potentially material liabilities relating to the investigation and clean-up of contaminated properties, and to claims alleging personal injury or property damage as the result of exposures to, or releases of, hazardous substances or as a result of accidents or other incidents at facilities managed by the Group or otherwise resulting from the Group s operations, all of which could have a material adverse effect on the Group s financial condition and results of operations. In addition, certain of the Group s contracts subject the Group to possible claims if the Group fails to meet certain environmental standards which may be more stringent than those imposed under the regulatory regime in force in the relevant country of operation. Stricter enforcement of existing laws and regulations, the introduction of new laws and regulations, the discovery of previously unknown contamination or the imposition of new or increased requirements could require the Group to incur costs or become the basis of new or increased liabilities that could reduce earnings and cash available for operations. The Group conducts its operations within a strict health and safety regime, particularly in the UKCS. Failure to comply with the relevant regulations could adversely affect its reputation and future revenues. The Group is subject to strict health and safety regimes, governing the full spectrum of its operations. The Group may be exposed to fines, penalties or prosecutions by governmental authorities in respect of non-compliance with applicable regulations. The Group s OS Division manages the operation of installations in the UKCS on behalf of a number of clients which own the installations and have been granted a production licence by the Department of Trade and Industry (DTI). As part of its management role in assisting certain clients to discharge responsibilities under their licences, the Group takes on full responsibility for the safe management of these offshore installations. In such cases, under the applicable offshore safety regulations, the Group is considered to be acting as duty holder in performing this role. The Group is responsible, amongst other matters, for preparing and updating a safety case, demonstrating that it has considered all the possible hazards that may occur on the installation, their likelihood of occurrence and how it has minimised the associated risks. The applicable offshore health and safety regulations are enforced by a team of inspectors from the UK Health and Safety Executive (H&S Executive). Improvement notices or prohibition notices may be filed or prosecutions may be brought against the Group by the H&S Executive for its failure to comply with these regulations. A prosecution in the area of health and safety could adversely affect the reputation of the Group, including in particular, its reputation as an operator offering duty holder capability. This, in turn, could adversely affect the future revenue and profits of the Group s OS Division, and its ability to generate new business. The Group s businesses may be subject to claims for professional errors and omissions. Providing project management, engineering and construction services involves the risk of contractual and professional errors and omissions and other liability claims, as well as adverse publicity that may adversely affect the Group s financial performance and condition. The Group 25

26 may not be able to maintain or obtain adequate insurance coverage at rates it considers reasonable or it may take the decision not to insure such risks. Even in the event coverage is obtained, claims may exceed such insurance coverage. Liability to clients under warranties may materially and adversely affect the Group s earnings. The Group provides warranties as to the services it provides and as to the proper operation and adherence to specifications of the engineering and construction services equipment it designs, modifies or constructs. Failure of this equipment to operate properly or to meet specifications may increase the Group s costs by requiring additional engineering resources and services, replacement of parts and equipment or monetary reimbursement to a client. Furthermore, these failures may cause significant and costly damage to the equipment. To the extent that the Group incurs substantial warranty claims in any period, its reputation, ability to obtain future business and financial performance and condition could be materially and adversely affected. The Group is, and may continue to be, involved in litigation. In the ordinary course of business the Group has been and may from time to time in the future be named as a defendant in legal actions in connection with the activities it carries out. These actions may include employment-related claims and contractual disputes (including claims by sub-contractors) or claims for personal injury or property damage which occurs in connection with services performed relating to project or construction sites. The Group has had operations and shareholders in the US and continues to have a small presence in the US. The Board considers the litigation risk in the US to be higher than in other jurisdictions. The Group currently is and may in the future be exposed to litigation in respect of past corporate actions and past and present operations. For further detail on current litigation in the US, please see paragraph 12 in Part IX Additional Information. In addition to being a defendant, the Group may also act as claimant or counterclaimant in certain actions, for example seeking recovery of monies owed. Any litigation could have adverse financial consequences for the Group, and the Group may not have adequately reserved for the potential losses associated with litigation payments. Litigation also involves a diversion of management time from the day-to-day running of the business. Negative outcomes of litigation in which the Group is involved may also adversely affect the Group s reputation. Damage to the Group s reputation and business relationships may have an adverse effect beyond any monetary liability arising. The Group s business depends on its client goodwill, its reputation and on maintaining good relationships with its clients, joint venture partners, employees and regulators. Any circumstances which publicly damage the goodwill of the Group, injure its reputation or damage its business relationships may lead to a broader adverse effect on its business and prospects by way of loss of business, goodwill, clients, joint venture partners and employees than solely the monetary liability arising directly from the damaging events. For example, the reputation of the Group as an entity offering to undertake the role of duty holder in the UKCS would be likely to be adversely affected by an incident which involved a serious breach of a health and safety regulation. Taxation risks Changes in certain fiscal regimes could adversely impact the financial condition of the Group. The Group s profitability is impacted by the levels of direct and indirect taxation levied on its profits and services and on the profits and services of its clients in the locations in which it operates. Increases in these direct or indirect taxes can adversely affect the returns that can be achieved by the Group and its clients and may result in a decline in revenues and profits. Such increases may, in particular, impact the returns to be made from the investments made by the Resources Division. In addition, the Group s OS and E&C Divisions operate in certain countries on the basis of certain tax exemptions granted to its client or a member of the Group by the government of a country in which a project is to be undertaken. Withdrawal of such exemptions could have an adverse impact on the 26

27 profit that can be achieved by the Group or its clients under the relevant contract and could, in certain cases, lead the Group or its clients to question the economic viability of their presence in that country. In addition, the interpretation of guidelines, rules and legislation by governmental taxation bodies in the countries in which the Group operates may change from time to time. The Group s conduct of operations may not be held to be consistent with such changes in interpretation, which could require the Group to change aspects of its operations which may correspondingly lead to a decline in revenues and profits. If the Company were deemed to be resident for taxation purposes outside Jersey, this could have adverse taxation implications. Although the Group as a whole pays tax in the jurisdictions in which it operates in accordance with local regulations, the Company itself is resident in Jersey. While the Directors have no reason to believe that any authority in any other jurisdiction could successfully claim that the Company was tax resident in that jurisdiction, there can be no assurance that such a claim will not be brought or, if brought, will not be successful. In this event, the Company could face penalties and charges to taxation in respect of current and earlier years, which could have a material adverse effect on the financial condition of the Group. Risks relating to the Ordinary Shares Because the Company is a holding company, it is financially dependent on receiving distributions from its subsidiaries. The Company is a holding company and all of its operations are conducted through subsidiaries. Consequently, it relies on dividends or advances from its subsidiaries, including those that are not wholly-owned. The ability of these subsidiaries to pay dividends, and the Company s ability to receive distributions from its investments in other entities, such as joint venture vehicles, are subject to applicable local laws and other restrictions, including, but not limited to, applicable tax laws and covenants in some of the Group s bank credit facilities. These laws and restrictions could limit the payment of dividends and distributions to the Company by its subsidiaries, which could restrict the Company s ability to fund other operations or to pay a dividend to holders of the Ordinary Shares. If the Company becomes a controlled foreign company for UK taxation purposes, a UK resident holder of 25 per cent. or more of the share capital of the Company would be exposed to a tax risk. The Company may become a controlled foreign company for UK taxation purposes following the Offer. As detailed in paragraph 11 of Part IX Additional Information, if more than 50 per cent. of the share capital of the Company is held by persons who are resident in the UK, the Company will be a controlled foreign company for UK taxation purposes. In this event, any UK resident company which, either alone or together with connected or associated persons, holds 25 per cent. or more of the share capital of the Company (or Ordinary Shares which entitle it to 25 per cent. or more of the income of the Company) may be assessed to corporation tax in respect of the profits of the Company which are attributable to such investor s interest in the Company. Although such an assessment may not be raised if the Company pursues an acceptable distribution policy, which broadly requires the Company to distribute annually 90 per cent. of its net chargeable profits as calculated for UK tax purposes, the Directors do not intend that the Company will pursue such a policy. The Group s reporting currency is different to the currency in which dividends will be paid. The Group s reporting currency is US Dollars and its dividend policy will be based on US Dollar financial results. Any dividends or other distributions in respect of the Ordinary Shares will be paid in Sterling and the market price of the Ordinary Shares will be reported in Sterling. Accordingly, investors will be subject to the risk of currency fluctuations between the declaration of a dividend in US Dollars and its payment in Sterling. In addition, the US Dollar dividend policy may not result in a consistent payout when expressed in Sterling terms. Investors may not be able to resell their Ordinary Shares at or above the Offer Price. Prior to the Offer, there has been no public market for the Company s Ordinary Shares. After the Offer, an active trading market for the Ordinary Shares may not develop or, if developed, may not be sustained. The Offer Price will be determined by negotiation between the Company, the Selling 27

28 Shareholders and the Underwriters, and may not be indicative of the price at which the Ordinary Shares will trade following the completion of the Offer. The market price of the Ordinary Shares could also be subject to significant fluctuation, and investors may not be able to resell their Ordinary Shares at or above the Offer Price. The availability of Ordinary Shares for future sale could depress the share price. Sales of a substantial number of Ordinary Shares in the public markets following the Offer, or the possibility that these sales may occur, could have a material adverse effect on the price of the Ordinary Shares or could impair the Company s ability to obtain further capital through an offering of equity securities. In particular, following the Offer the Directors will have a beneficial interest in up to approximately 35 per cent. and the Group s Directors and Senior Managers together with other employees as a group will have a beneficial interest in up to approximately 49 per cent. of the Ordinary Shares. The Group cannot predict whether substantial numbers of Ordinary Shares in addition to those which will be available in the Offer will be sold in the open market following the expiry of the lock-in arrangements described in paragraph 6 of Part VIII Details of the Offer. In particular, there can be no assurance that, after the expiration of these arrangements, the relevant shareholders will not reduce their holdings of Ordinary Shares. Furthermore, the Group cannot predict what effect, if any, market sales of Ordinary Shares held by any shareholders or the availability of these Ordinary Shares for future sale will have on the market price of the Ordinary Shares. 28

29 PART III Information on the Petrofac Group 1. Overview Petrofac is a leading international provider of facilities solutions to the oil and gas production and processing industry, with a diverse client portfolio which includes many of the world s leading integrated, independent and national oil and gas companies. Petrofac has a presence in the UK Continental Shelf (UKCS), where there has been rapid growth in operations and management services for mid- and late-life fields, as well as the growing new development regions of the Middle East, North Africa and the Former Soviet Union (FSU). Through its three divisions, Engineering & Construction, Operations Services and Resources, Petrofac designs and builds oil and gas facilities; operates, maintains or manages facilities and trains personnel; and, where return criteria are met and revenue synergies identified, co-invests with clients and partners. Petrofac s range of services allows it to help meet its clients needs across the life cycle of oil and gas assets. Petrofac operates out of four strategically placed international centres in Aberdeen, Scotland; Sharjah, UAE; Mumbai, India; and Woking, England, and has a further 13 offices worldwide, with approximately 5,500 employees. Through both organic growth and strategic acquisitions, Petrofac has grown significantly from inception of the business. In FY 2004, total revenue from continuing operations was US$951.5 million, with a net profit attributable to Petrofac shareholders of US$46.1 million compared with US$628.7 million and US$38.4 million respectively in FY In H1 2005, Petrofac s total revenue from continuing operations was US$692.4 million, with a net profit attributable to Petrofac shareholders of US$36.4 million. Since 2002, Petrofac s total revenue has grown at a compound annual growth rate of approximately 56 per cent. In addition, Petrofac has increased significantly and diversified its backlog, which stood at US$2.5 billion at 30 June Petrofac s revenues from continuing operations categorised by division for FY 2004 and, in aggregate, for FY 2002, FY 2003 and FY 2004, together with the revenues for H (unaudited) and H1 2005, are shown below. Petrofac s EBITDA from continuing operations (before consolidation and elimination adjustments) split by division for FY 2004, and, in aggregate for FY 2002, FY 2003 and FY 2004, together with the EBITDA for H (unaudited) and H1 2005, are shown below. 29

30 Petrofac s net profit attributable to its shareholders from continuing operations (before consolidation and elimination adjustments) split by division for FY 2004 and, in aggregate, for FY 2002, FY 2003 and FY 2004, together with the net profit for H (unaudited) and H are shown below. Petrofac s business is carried out principally in the geographical areas of Europe, the Middle East, North Africa and the FSU. Revenues for FY 2004 were US$392.1 million in Europe, US$281.7 million in the Middle East & Africa, US$272.4 million in the FSU/Asia and US$5.4 million in the Americas. Engineering & Construction Division (E&C Division) The E&C Division provides services to oil and gas industry clients to develop, design and construct facilities, including: integrated engineering, procurement and construction services, including project management, engineering, procurement services and the construction management and commissioning of oil and gas facilities; and specialist engineering and consultancy services, including preparation of field development plans and associated studies, design development, front end engineering and design (FEED), demanning and decommissioning studies, and the provision of risk, safety and environmental consultancy services. Major EPC contracts are typically undertaken on a lump sum, or fixed price basis, while engineering and consultancy services are often provided on a cost reimbursable basis. Operations Services Division (OS Division) The OS Division provides services to oil and gas industry clients to operate, maintain and modify facilities and train personnel, including: facilities operations and maintenance services for onshore and offshore installations, principally in the UKCS but with an increasing presence outside the UKCS, including the provision of operations management, maintenance services and consultancy, brownfield engineering services and specialist manpower; and specialist training and human resource development, including safety training, operations and technical training, emergency response and critical incident management training; and training support and management services. The Group s facilities operations and maintenance services are typically provided under long term, cost reimbursable contracts which include performance related remuneration, while the basis of remuneration for the Group s training services varies depending on the scope of the services being provided by the Group. Resources Division In selected situations, the Resources Division invests alongside its clients and partners in producing and proven or probable but not fully developed oil and gas reserves and energy infrastructure. Investments are assessed on the basis of their projected financial return reflecting the anticipated risks of the investment, and independently, the opportunity for the Group to provide services to its clients and partners. 30

31 Industry conditions As a provider of services to the oil and gas industry, Petrofac s revenues are driven by three broad factors: (i) the level of capital expenditure of the oil and gas industry to develop proven and probable hydrocarbons and construct related hydrocarbon processing, transportation and refining facilities; (ii) the level of operations outsourcing by oil and gas companies; and (iii) the industry-wide requirements for trained personnel. In turn these three factors are affected by current and expected levels of oil and gas prices. Over the long-term, global economic growth is expected to continue to drive demand for oil and gas resources. According to the BP Statistical Review of World Energy June 2005, there is limited excess production capacity relative to demand and since 2004 this has led to significant increases in current and expected oil and gas prices. The additional supply necessary to match the expected increase in demand is likely to require an increased level of spending across the life cycle of oil and gas production assets from drilling to field development to maintenance, modification and operations. Further, as remaining reserves are developed in increasingly remote regions with undeveloped hydrocarbons transportation infrastructure (for example, areas such as the Caspian Sea region, onshore North Africa and Eastern Siberia), significant infrastructure expenditure is necessary to bring these reserves to market. The Worldwide Petroleum Industry Report expects growth in capital expenditure to average 6.7 per cent. per annum during the period , increasing from US$152 billion to US$172 billion per annum. The Middle East and Africa are predicted to see the highest growth out of all regions of about 9.1 per cent. per annum, representing 10.7 per cent. of the total capital expenditure in In addition, a global shift towards heavier crude oils, increasing regulatory requirements, and demand for clean fuels are driving the construction of new refineries and infrastructure upgrades. As an international provider of engineering and construction and operations services, Petrofac stands to benefit directly from these increases in capital and operating expenditure by oil and gas companies. In addition, as a direct equity investor in selected oil and gas projects, Petrofac may benefit from higher hydrocarbon prices. Higher oil prices are also contributing to a currently strong market for maintenance, modification and operations services. This market strength is due to the favourable impact higher oil prices have on the economics of higher cost fields. As evidence of this trend, the operating costs per barrel of oil equivalent (boe) produced has increased substantially from 1999 to 2004: for 20 international oil companies, national oil companies, and independent oil companies producing an aggregate of approximately 30 million boes per day in 2004, the weighted average operating cost 1 increased from US$3.95/boe produced in 1999 to US$6.14/boe produced in 2004, representing a compound annual growth rate of 9.3 per cent. 2. The Directors believe that this trend is likely to enhance further the opportunities for the OS business. Structure of the oil and gas sector The oil and gas sector is comprised of major integrated companies, independent companies and national oil companies. The major integrated companies are involved in all stages of the energy chain, from the exploration and production of hydrocarbons, to transportation and shipping, refining and marketing, and the production of petroleum or natural gas derived chemicals and related products. These major integrated companies operate globally and compete for large scale projects. A range of smaller, independent companies are also active in the oil and gas sector. Many of these are focused on the exploration and production of hydrocarbons, although there are several companies which are exclusively engaged in the refining, marketing and petrochemicals segments. The oil and gas sector in many emerging market oil producing and consuming economies is dominated by large national oil companies, predominantly, if not exclusively, owned by their respective host countries. These national oil companies often retain legal ownership of all hydrocarbon resources in their respective countries. Three ongoing trends are affecting the structure of the oil and gas industry. First, during the 1990s, oil and gas companies adjusted their business models to focus on reservoir identification and management, and activities such as project and facilities management have subsequently been 1 Lifting costs; excluding DD&A and exploration expense 2 Data source: JS Herold 31

32 outsourced to an increasing degree. Second, there has been a trend for the major integrated oil companies to divest their more mature and smaller-scale fields to independent E&P companies. This trend has been evident in the UKCS, where Petrofac is a significant provider of facilities management services through its OS Division. Third, although the national oil companies have historically relied upon major integrated or independent companies to operate and manage their fields through concession or license agreements, they are increasingly seeking to develop their reserves and operate their production processes themselves, rather than allow international companies to control the development of fields. As such, the national oil companies are awarding an increasing proportion of construction contracts and facilities maintenance contracts in the sector. The Directors believe that the nature of Petrofac s service offerings and its existing customer relationships with the independent E&P companies and the national oil companies position it to benefit from each of these three trends. Relative sensitivity of oil and gas sector service offerings to hydrocarbon prices Exploration and production spending is generally categorised as either operating or capital expenditure. Activities designed to add and produce hydrocarbon reserves are classified as capital expenditure, while those associated with maintaining or accelerating production are categorised as operating expenditure. Capital expenditure tends to be relatively sensitive to volatility in oil and gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often requires the use of commodity price forecasts which may prove inaccurate over the full life of the project. Periods of low commodity prices have been associated with lower levels of capital expenditure as projects are deferred until prices return to an acceptable level. In contrast, levels of both mandatory and discretionary operating expenditure are substantially less correlated to current and expected hydrocarbon prices than exploration and drilling expenditure. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, performance of contractual obligations and projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field but the economic viability of these projects is relatively insensitive to commodity price volatility. Discretionary operating expenditure work is often evaluated according to a simple short-term payout criterion which is far less dependent on commodity price forecasts. Petrofac s business is influenced substantially by both operating and capital expenditure by oil and gas companies. Because existing oil and gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for maintenance of existing facilities are relatively stable and predictable compared to exploration and drilling expenditures. In contrast, capital expenditures by oil and gas companies for exploration and drilling are more directly influenced by current and expected oil and gas prices and generally reflect the volatility of commodity prices. 2. History The Group has its origins as a Texas based engineering, procurement and fabrication (EPF) business founded in Petrofac operated as both a domestic and an international engineering, procurement and fabrication contractor, principally focused on the design and fabrication of modular plant for the upstream oil and gas and downstream refining markets. In 1991, recognising the increased opportunities in international markets, Petrofac recruited Ayman Asfari (the Group Chief Executive) and Maroun Semaan (Chief Executive of the E&C Division) to open a new office in Sharjah, UAE. This brought international commercial, construction and project management skills into the Group, which developed full service EPC capabilities targeting the rapidly growing Middle East, North Africa and FSU markets. Petrofac sought to differentiate its E&C business by developing the capability to invest alongside certain clients through the establishment of the Resources business in In 2000, Petrofac committed over US$100 million in investment by taking a 10 per cent. interest in the Ohanet development in Algeria alongside BHP Petroleum, the operator, and other international partners 32

33 and secured a major EPC contract to construct the gas processing facilities for this development in a joint venture with ABB Lummus. The successful completion of the Ohanet EPC contract in 2003 which, at that time, was the largest contract undertaken by Petrofac, significantly enhanced Petrofac s reputation to undertake large-scale and complex projects. The Ohanet investment continues to generate strong financial returns and forms the core of the Resources Division s portfolio. In 2001, Petrofac expanded its E&C services to include development and field facilities planning, early stage engineering, design and consultancy, through a new office established in Woking, England. This office has since developed capabilities for detailed engineering and project management services for small and large scale facilities projects, both onshore and offshore. Prior to January 2002, the Group s operations were owned and operated through a combination of companies organised in the United States and other countries in which a group of common shareholders owned various share interests. The principal group holding company was Petrofac Corporation Limited (PCL). In January 2002, the Group completed a corporate reorganisation through which the Company acquired full ownership of PCL and of the minority interests in PCL s subsidiaries that PCL did not already directly or indirectly own. The Company also purchased certain assets from the minority shareholders of Petrofac LLC and the remaining minority interest in Petrofac LLC. The reorganisation resulted in PCL becoming a wholly owned subsidiary of Petrofac Limited and PCL wholly owning each of its direct subsidiaries. Subsequently, PCL was merged into Petrofac Limited. These reorganisation transactions included the issuance of ordinary and preference shares and the payment of cash. Financial information for the 2002 financial year contains a full year s contribution from Petrofac s predecessor companies. In May 2002, Petrofac raised long term capital from 3i Group plc (3i) through the issuance of US$40.25 million variable rate unsecured loan notes maturing in 2009 together with the grant of an option to purchase Petrofac A ordinary shares representing 13.0 per cent. of the fully diluted ordinary share capital of Petrofac. Following completion of the purchase and cancellation of approximately 25 per cent. of the Company s issued ordinary share capital in 2004, 3i s option was increased from 13.0 per cent. to 16.2 per cent. In June 2005, the conditions allowing the Company to call upon 3i to subscribe for its 16.2 per cent. interest were met and the aggregate subscription amount was satisfied by the cancellation of the loan notes and the issue of A ordinary shares to 3i. As the E&C business expanded internationally, Petrofac decided to divest its loss-making US operations due to their lower growth prospects and reduced strategic value to the future of the Group. In 2003, it sold its US EPF business to Chicago Bridge & Iron Company N.V. on terms whereby Petrofac retained contractual responsibility for the work in progress at the date of sale. The physical work under such contracts was substantially completed by 30 June The results of this business have been separately classified as a discontinued operation within the Group s accounts. During the late 1990s, Petrofac began to develop a facilities management capability to take advantage of growing trends towards the outsourcing of non-core activities by the oil and gas producers. It secured contracts to manage refineries in Fujairah, UAE and Kyrgyzstan, FSU, where it also had an investment in the operation, and a gas processing facility in Bolivia. In 2002, Petrofac separated these operations into a new facilities management business unit. Later that year, Petrofac significantly increased the scale of its operations services activities with the acquisition for US$28.1 million of PGS Production Group Limited, trading as PGS Production Services (PGS PS), a leading operations and maintenance provider in the UKCS. Petrofac recognised the growing need to train the next generation of industry workers due to the shortage of skilled personnel, together with the growing importance of safety and environmental risk management to its client base. In 2003, Petrofac developed a training and competence management capability within its OS Division, initially through the acquisition of a small competence and production training business, Chrysalis Learning, followed, in 2004, by the more significant acquisition of RGIT Montrose, a leader in the provision of fire and safety training services, for US$17.2 million. In 2005, the training business was further strengthened by the acquisition of an emergency response and crisis management consultancy, Rubicon Response, for US$6.3 million. 33

34 With the addition of development planning and early stage engineering services, facilities management and training and investment to the original EPC business, Petrofac now offers the capability to optimise clients capital and operating expenditures throughout an asset s life cycle and provide alignment through equity or mezzanine financing participation, where appropriate. 3. Business strategy The Directors goal for the Company is to generate sustainable growth in value for Petrofac s shareholders by being a leading international provider of facilities solutions to the oil and gas industry, delivering world-class project development, project management, engineering, procurement, construction, operations and training services, focusing on oil and gas production facilities, gas plants, oil refineries and pipeline transportation systems. The Directors aim to achieve this goal by: Leveraging client relationships by providing a range of services across the life cycle of an asset While each of the Group s divisions pursues new business opportunities independently, where appropriate, Petrofac seeks to leverage its competence and expertise across all of its service offerings to secure additional revenues. The Directors believe that clients derive greater benefit when working with service providers which can support all phases of an asset, from conceptual design through construction and operations and, ultimately, to decommissioning, and can accompany this with project co-investment where appropriate. This approach may mitigate the risks inherent in monetising hydrocarbon assets by optimising both capital and operating costs over the life of the asset and aligning the service provider to the financial risk and reward of the development. Focusing on regions with major hydrocarbon reserves where significant capital and operational expenditures are expected Petrofac s activities outside the UKCS are predominantly focused on the Middle East, North Africa and FSU regions where, in aggregate, approximately 65 per cent. of the world s proven hydrocarbon reserves are located and where significant capital and operational expenditures are required to bring these reserves to market efficiently. Petrofac has strong relationships and significant experience of operating in these regions and, with its Sharjah and Mumbai locations and its extensive network of country offices, has a well established infrastructure to support its activities in these areas. Expanding Petrofac s established service offering into new countries and regions Petrofac takes business lines developed in one of its markets into its other core geographic territories. For example, Petrofac has a market leading operations management business in the UKCS where there is an established history of licence operators outsourcing production services operations. In recent years, Petrofac has taken this business model into other geographic markets such as Kuwait where traditionally these activities have been performed in-house. Similarly, Petrofac s training business had origins in the UKCS and is now operating in other locations around the world. The Directors believe there is substantial scope to bid for operations services contracts in the Middle East, North Africa and the FSU as the national oil companies within these regions increasingly seek to develop resources on their own and retain ownership of midstream refining and processing facilities, by utilising the expertise and resources of international contractors such as Petrofac. Assisting clients in achieving their local content goals by increasing the use of indigenous resources and improving the competence and technical skills of local workforces Petrofac s E&C Division has long-established relationships with local partners and sub-contractors in its areas of operations, which can assist clients in meeting the local content requirements of host governments. Furthermore, through its training operations, Petrofac can manage and provide dedicated on-site training programmes to local workforces. The Directors believe that developing technical competence within the local workforce is becoming an issue of increasing importance, particularly for governments in developing 34

35 economies which have good standards of higher education but high levels of unemployment. The Directors believe that Petrofac s operations and safety training capability provides Petrofac with a competitive advantage by enabling it to assist national governments in achieving their strategic goals. Improving revenue and earnings stability through a diversified and complementary business model The Directors believe that the Group s three divisions provide diversification and synergy benefits and therefore provide Shareholders with a more balanced exposure to risk and greater stability of revenues and earnings. The differing project scope and contract profile of each division highlights this diversity. The E&C Division typically undertakes lump sum EPC projects where revenues and earnings are recognised over the life of the contract, typically one to three years. The OS Division typically provides services on a cost reimbursable basis with potential performance-linked bonuses over contracts that can last for five years or more. Investments made by the Resources Division are designed to provide an investment return once the project has been completed. The Group seeks incremental revenues through the provision of services on a combined basis where practical, and benefits from internal expertise across the divisions when pursuing and executing new business. Attracting and retaining recognised specialists and key personnel Petrofac recognises that the ability to attract and retain high calibre personnel is critical to the delivery of its existing services, maintaining competitive positioning and the continued growth of its business. Petrofac is committed to the professional and operational development of employees and encourages an ethos of individual responsibility and recognition. The Directors believe Petrofac s open and accessible culture to be a major factor in the retention of employees. The Directors believe that Petrofac s success to date is attributable in part to its culture of share ownership which aligns the interests of employees with those of Petrofac and which assists in building long term sustainable value across its business areas. Following Admission, interests in approximately 15 per cent. of the issued share capital of the Company will be held by approximately 300 employees below Board level. Petrofac has put in place new employee share schemes designed to continue this alignment. Maintaining and improving on high safety standards Petrofac is a socially responsible employer and contractor with a commitment to operate to high health, safety and environment (HSE) standards. Petrofac seeks to ensure that its employees are aware of, and take individual responsibility for, HSE matters in an environment where safety is regarded as a high priority. The Directors believe that high safety standards are important in maintaining Petrofac s reputation and ability to win and retain significant contracts and consider that its role as a leading provider of safety training is lent credibility by its own strong safety record. Identifying, acquiring, integrating and developing complementary businesses, where appropriate While Petrofac s primary focus is on delivering organic growth from its existing businesses, it also considers opportunities to broaden its service offering or extend the geographic reach of existing services through the acquisition of complementary businesses that are considered to be a good fit with the Group s culture and strategy. 4. Description of the business Through its three divisions, Engineering & Construction, Operations Services and Resources, Petrofac designs and builds oil and gas facilities; operates, maintains or manages facilities and trains personnel; and, where return criteria are met and revenue synergies identified, co-invests with clients and partners. Petrofac s range of services allows it to help meet its clients needs across the life cycle of oil and gas assets. 35

36 Engineering & Construction Petrofac s Engineering & Construction Division focuses on project development and value engineering services and the provision of integrated engineering, procurement and construction (EPC) services for the oil and gas industry. Through Petrofac s origins in the US in 1981, the Group has nearly 25 years experience in oil and gas production, processing and refinery projects. The E&C Division operates principally from Sharjah, UAE; Mumbai, India; and Woking, England, with approximately 1,750 employees. In FY 2004, the E&C Division s external revenue was US$467.1 million with net profit of US$33.1 million, representing 49 and 72 per cent. respectively of the Group for that period. In H1 2005, the E&C Division s external revenue was US$390.2 million with net profit of US$23.0 million, representing 56 and 63 per cent. respectively of the Group for that period. At 30 June 2005, the backlog for the E&C Division was US$1.0 billion. The provision of integrated EPC services contributes the predominant share of the E&C Division s financial performance. Industry outlook Demand for oil and gas engineering and construction services is dependent on the capital investments undertaken by oil and gas companies that in turn are largely driven by energy prices and demand. Oil prices have recently achieved all-time highs with the Brent crude oil reference price exceeding US$60 per barrel and, according to International Energy Agency (IEA) estimates, global energy consumption is expected to grow by 60 per cent. over the next 20 years, driven primarily by continued economic growth particularly in developing economies such as China and India. Due to the limited opportunities to discover new reserves, oil and gas companies have increased their capital expenditure budgets to develop their existing reserves and are also reinvesting to maximize the life and production of their existing assets. New reserves are often located in remote areas and require material investments in drilling, processing and transportation infrastructure. In addition, a global shift towards heavier crude oils, increasing regulatory requirements and demand for clean fuels are driving the construction of new refineries and infrastructure upgrades. Engineering, procurement and construction Petrofac provides integrated EPC services for oil and gas facilities focusing on the Middle East, North Africa and the FSU. Petrofac s EPC expertise covers oil and gas gathering, processing and transportation in both greenfield and brownfield developments, with the ability to tailor construction planning and detailed scheduled activities around specific site conditions. Petrofac s role in a lump sum EPC contract will generally include design, detailed engineering, procurement of equipment and materials, construction management and commissioning. Petrofac s main EPC operating base is in Sharjah, UAE, with an engineering office in Mumbai, India. These offices are supported by an extensive network of regional offices and project site offices which provide additional engineering and project management capability as well as in-depth knowledge of local markets. The EPC business has approximately 1,600 employees. This does not include temporary and local employees appointed by the BTC/SCP joint venture (as Petrofac does not typically directly employ temporary or local labour itself to work on its EPC projects, or include such employees in its employee count). Engineering Petrofac employs experienced teams across core engineering disciplines to meet its clients engineering needs, including process engineering, instrument, control and telecommunications engineering, electrical engineering, mechanical engineering, rotating equipment engineering and civil and structural engineering. Core areas of expertise include: oil gathering and production facilities; crude oil stabilisation; liquified petroleum gas (LPG) and natural gas liquids (NGL) recovery including turboexpander plants; 36

37 gas processing, separation and compression; oil refining; sulphur recovery; oil terminals and pumping stations; water treatment and injection; and flowlines and pipeline systems. Procurement Petrofac uses established competitive tendering procedures to seek to procure equipment and services globally. Petrofac s procurement offices are located in the UAE, UK and USA, together with project offices located in various countries of operation providing support to the procurement process. Petrofac sources equipment and materials from pre-qualified vendors and suppliers and regularly monitors the vendors product quality and delivery performance. Vendors are supervised through approved test and inspection plans and periodic inspections by experienced in-house inspectors. Petrofac may post its own expediters at a vendor s place of operation to supervise the delivery of all critical equipment and also engages third party inspectors for independent inspection at key stages of the project and at completion. Construction Petrofac is not a construction company, rather it provides expert construction management services, including the organisation and supervision of sub-contractors, through the construction phase of a project. Petrofac generally uses the services of local and international construction contractors, whilst maintaining responsibility for construction and the quality and health and safety aspects of a project. With experienced construction managers and supervisors with established track records, Petrofac has expertise in sub-contractor management, fabrication and onsite construction, commissioning, overall site construction management, clearance, logistics and handling of imported equipment and materials, systems for developing health and safety procedures and detailed pre-commissioning, commissioning and operations manuals. Construction projects are often carried out in extreme and remote environments. Clients Petrofac s major EPC clients include Agip Kazakhstan North Caspian Operating Company N.V. (AGIP KCO), BHP Petroleum, BP, Kuwait Oil Company (KOC), Petroleum Development Oman LLC, Qatar Petroleum and Total S.A. Contracts Petrofac has historically targeted contracts in the range of US$50 million to US$700 million. Most of Petrofac s EPC contracts are undertaken on a lump sum basis, meaning that Petrofac s revenues consist of an all inclusive lump sum price for the completed project. Petrofac has a disciplined approach to project selection and will not bid, or will discontinue a bid, where the Directors believe its selection criteria (relating to margins, availability of resource, reputation and risk management, among other things) are not achievable. For further information on risk management, please see paragraph 6 of this Part III. Examples of contracts on which the engineering, procurement and construction business is currently working or which it has recently completed include: AGIP KCO Kashagan field, Kazakhstan Petrofac is undertaking the main engineering and procurement contracts with AGIP KCO (a consortium including Eni SpA, Royal Dutch Shell plc and the national oil company of Kazakhstan) in relation to the onshore oil, gas and sulphur plants for the Kashagan oil field in Kazakhstan. The value of the contracts is over US$500 million. The contracts were signed in August 2004 and are due to be completed in March

38 Qatar Petroleum Mesaieed, Qatar Petrofac is undertaking an engineering, procurement, installation and commissioning contract for Qatar Petroleum at its Mesaieed complex in Qatar where Qatar Petroleum owns and operates four NGL plants. The contract value is US$173 million. The contract was awarded in April 2004 and the project is due to be substantially completed by the end of Crescent Petroleum Sharjah, UAE Petrofac was awarded an EPC contract by Crescent Petroleum Company International Ltd for a new gas processing facility in Sajaa, Sharjah. The value of the contract on announcement was US$82 million. The contract was awarded in April 2004 and is due to be completed during the fourth quarter of Kuwait Oil Company facilities upgrade, Kuwait Petrofac is working on a contract for KOC to undertake the facility upgrade and relocation of underground process piping in KOC s gathering centres and booster stations. The value of the contract on announcement was US$644 million. The contract was awarded in April 2005 and is expected to be completed by year end BP BTC (Baku-Tbilisi-Ceyhan) and SCP (South Caucasian Pipeline) pipelines, Georgia and Azerbaijan Petrofac is working with its joint-venture partner Amec-Spie S.A. (Amec) on a contract with BP Exploration (Shah Deniz) Limited to build the 248 km Georgia stretch of the BTC and SCP oil and gas pipelines, as well as the associated pumping and metering stations in Georgia and Azerbaijan. The contract value is approximately US$800 million, with Petrofac having a 50 per cent. share. The contract was awarded in August 2002 and is due to be substantially completed at the end of Although work on the oil pipeline and facilities is now substantially complete and the introduction of oil commenced in May 2005, the project has suffered from extensive delays resulting in significant cost overruns. The joint venture has filed claims for costs overruns and associated claims. Further detail of the claims made are set out in paragraph 12 of Part IX Additional Information. BHP Petroleum Ohanet gas field, Algeria Petrofac was awarded a contract in a 50/50 joint venture with ABB Lummus by BHP Petroleum for the redevelopment of the Ohanet surface facilities, in which Petrofac also invested through its Resources Division. The final contract value was approximately US$600 million, with Petrofac having a 50 per cent. share. The contract was awarded in October 2000 and the project was completed in February Competitors Petrofac s competitors on major lump sum projects include Technip S.A., Japan Gas Corporation, Snamproggetti SpA. (part of the Eni SpA group), Bechtel Corporation and KBR (part of the Halliburton Inc group), whilst its competitors on mid-sized projects include Technicas Reunidas, SNC-Lavalin Group Inc. and various Korean contractors. The Group also faces competition from Larsen & Toubro Limited, Punj Lloyd Ltd, the Dodsal group and China Petroleum Engineering & Construction Group. Engineering and consulting services Petrofac s engineering and consulting services business is a specialist provider of greenfield and brownfield engineering services and assists clients in planning and assessing the feasibility of engineering projects in Europe, the Middle East, Africa and the FSU. The engineering and consulting services business operates principally from offices in Woking, England and Aberdeen, Scotland and has approximately 150 employees. Petrofac s engineering and consulting services include: the preparation of full field development plans and associated technical, commercial and risk studies working with its clients to establish and document whether a business opportunity or a hydrocarbon find is technically feasible and has economic potential to justify further development; 38

39 design development seeking to identify relevant and feasible technical and commercial concepts and undertaking further work to evaluate and define the selected project option and confirm that the business opportunity will be in line with corporate objectives; FEED services developing and documenting the basic engineering and design and cost estimates, based on the selected concept, to such a level that a final project decision can be taken, applications to authorities can be made and contracts for project implementation can be entered into; design packages used by Petrofac and its clients to enable the preparation of field development plans, master participants plans and invitations to tender; de-manning and decommissioning studies advising the client on options for exit upon cessation of production, how to manage that exit process and means of disposal of plant and equipment; and independent consultancy and engineering services and studies health, safety and environmental studies, process engineering and flow assurance, engineering and design services, value engineering and operability and operational enhancement studies. Clients Petrofac s major engineering and consulting services clients include Anadarko Petroleum Corporation, BG Tunisia, BP, Burlington Resources, Lundin Petroleum AB (Lundin), Norsk Hydro, RWE Dea AG, TNK-BP (Rospan), Qatar Petroleum, the Oil and Energy Industry Development Company (OEID), a subsidiary of the National Iranian Oil Company, and Statoil ASA. Contracts The basis of Petrofac s engineering and consulting services business is the delivery of engineering services and associated documentation together with project cost estimates and schedules. The products range from delivery of a study report or a technical design basis, through development of a FEED/EPC tender packages to providing the services of an individual or taking on full project management responsibility on behalf of the client. Contracts range in duration from a single day (for example for a hazard or operability (HAZOP) review) to a few weeks for a study, to several months for a FEED or up to three years for a service contract (with no guaranteed workload). Generally the limit of liability will be for re-performance of services in the event of defective work. Due to the nature of its products, the engineering and consulting services business carries professional indemnity insurance. Engineering and consulting services contract terms vary from lump sum based contracts to rate reimbursable contracts with contract ceilings. Contract values can range from studies up to a value of US$100,000, through to conceptual and front end engineering contracts in a typical range of US$500,000 to US$3 million, with occasional larger design services or front end engineering contracts of US$3 million up to US$10 million. Where Petrofac undertakes a project management contract, this value may be considerably higher depending on the extent of, inter alia, procurement. The frequency of small contracts provides the Group with access to a wider range of potential clients than it might otherwise achieve. Examples of contracts on which the engineering and consulting services business is working or which it has recently completed are: BP Amoco and La Société Nationale Sonatrach In Amenas, Algeria Petrofac is providing engineering and procurement services to BP Amoco Exploration and La Société Nationale des Hydrocarbures (Sonatrach) in relation to the Tiguentourine gas condensate field, which is part of the In Amenas project in Algeria, North Africa. Petrofac is also assisting with the selection of the construction contractor. The contract was awarded in December 2003 and is due to be completed in early Lundin Netherlands Oudna, Tunisia Petrofac is providing engineering and project management services to Lundin Netherlands B.V. in relation to the Oudna field in Tunisia, North Africa. The contract was signed in November 2004 and is due to be completed at the end of

40 Addax Petroleum Development Adanga and Oron, Nigeria Petrofac is providing project management, engineering and design services to Addax Petroleum Development (Nigeria) Limited in relation to the Adanga and Oron platforms in offshore Nigeria, Africa. The contracts were awarded in March 2003 and services are expected to be completed by the end of TNK-BP (Rospan), Russia Petrofac undertook a FEED study for Rospan, a subsidiary of TNK-BP, in relation to the Rospan gas and condensate field in Russia, FSU. The contract was awarded in May 2004 and completed in December During 2005, further engineering services were provided in relation to safety and integrity upgrades for the gas plant. Competitors The main competitors of Petrofac s engineering and consulting services business are UK or European EPC contractors and consultants. These include Technip (especially its specialist front end subsidiary, Genesis), KBR (especially its specialist front end subsidiary Granherne), Worley Parsons, Wood Group (including its subsidiary, Woodhill Engineering Consultants), INTEC Engineering, IGL, John Brown Hydrocarbons, Bechtel and Amec. Competitive strengths of the E&C Division The Directors believe that the competitive strengths of the E&C Division include the following: Disciplined project evaluation and selection Drawing on its experience and strong track record of completing projects on time and profitably, the Group has developed risk management procedures that seek to identify and mitigate the risks inherent in lump sum EPC business. Proven in-house expertise in engineering design and project execution Petrofac s E&C Division has completed over 70 engineering and design and EPC contracts since 1991 alongside over 200 engineering and consulting contracts. Petrofac has proven engineering, procurement, construction and commissioning capabilities, and the Directors believe that Petrofac s strong track record highlights its demonstrable expertise in project execution and this gives the Group an advantage in competitive tender situations. In addition, Petrofac has access to specialist front-end engineering skills through its operational office in Woking, England. Proven project execution capability in challenging and geographically remote areas Petrofac has successfully completed EPC contracts in a variety of challenging and geographically remote oil and gas producing regions, including for example, the Kharyaga project in the Russian Arctic region and the Ohanet project in the Algerian desert. Such projects demonstrate its ability to manage and execute projects notwithstanding challenging geo-political or environmental conditions. Established client relationships with both international and national oil companies Petrofac has strong relationships with international integrated oil companies, independent oil companies and NOCs. The Directors believe such relationships will allow it to capitalise on any potential changes in the structure of the industry including, in particular, the increase in activity of NOCs. Access to high calibre engineering personnel from low cost countries Petrofac is able to call on a pool of high quality, highly qualified and motivated individuals through its operational offices in Sharjah, UAE and Mumbai, India at a lower cost than if it had to source staff of equivalent calibre from Western Europe or the USA. Established local relationships with partners and sub-contractors The E&C Division has established relationships with local partners and sub-contractors in its areas of operation. Petrofac s experience in the management of diverse cultures and working environments helps foster constructive employee and sub-contractor relationships. 40

41 Operations Services Petrofac s Operations Services Division consists of two business activities. The first, Petrofac Facilities Management, offers managed outsourced operations, maintenance and support services to oil and gas installations. Petrofac currently either operates or provides services to 30 platforms in the UKCS, operating the facilities for 16 fields, and is the leading outsourced oil and gas process facilities manager in the UKCS. These platforms produce approximately 0.9 million boe per day, representing almost 25 per cent. of current UK production activity. The division has also recently expanded into the Middle Eastern and Asian markets. The second activity, Petrofac Training, provides safety and technical training and consultancy services to the oil and gas industry. Petrofac Training trains over 30,000 delegates annually, and has provided training and consultancy services in over 26 countries. The OS Division is based in Aberdeen, Scotland, and Sharjah, UAE, and employs approximately 3,600 employees. In FY 2004, the Operations Services Division s external revenue was US$439.4 million with net profit of US$9.6 million, representing 46 and 21 per cent. respectively of the Group for that period. In H1 2005, the Operations Services Division s external revenue was US$279.6 million with net profit of US$7.3 million, representing 40 and 20 per cent. respectively of the Group for that period. At 30 June 2005, the backlog for the Operations Services Division was US$1.5 billion. Industry outlook Since the early 1990s, a number of the world s major integrated and independent oil and gas companies have been outsourcing certain of their global maintenance, modification and operations service requirements. More recently, NOCs have started to follow a similar trend. Outsourcing is often viewed as a compelling alternative by producers who recognise that it allows them to focus on their core competencies, enhance their safety performance and reduce costs. Given Petrofac s strong market share in the UKCS and its international presence, the Directors expect it to benefit directly from this trend. The training needs of the oil and gas sector have increased with the move to more demanding facility locations (such as offshore production), developments in countries where local manning may be required or desired as a matter of local policy, and an increased regulatory emphasis on safety. Facilities Management Petrofac provides operations, maintenance and turnkey facilities management for the oil and gas industry. The Facilities Management business has approximately 3,400 employees. The key component services of Petrofac s Facilities Management business include: management of oil and gas facilities on a turnkey basis on behalf of oil and gas company clients; maintenance management of important oil and gas production equipment; machinery management of critical offshore equipment; maintenance consulting services regarding the design and operational performance of a client s plant, including modelling to improve design, risk assessments and condition monitoring through CBMNet, an internet-enabled service operated remotely; recruitment and provision of personnel providing skilled offshore personnel to the drilling, marine, production and construction sectors, on placements, short-term supply or on a contract crew basis. At any one time, approximately 500 to 600 personnel are supplied to clients through Petrofac s Atlantic Resourcing and associated international manpower agency units. In a support role, Petrofac also offers project management of the process of recruitment, induction and placement to site as well as advice on personnel payroll, tax and insurance issues; and operational effectiveness audits of how platforms are being managed (conducted on third party managed platforms as well as platforms managed by Petrofac). 41

42 Petrofac s services are offered either as component services to facilities managed by owners (Operations Support) or together as a more comprehensive service offering to facilities where Petrofac has overall management responsibility, known as turnkey facilities management (Operations Management). Through the knowledge, experience and perspective gained across the various aspects of facilities management, Petrofac has developed the capability to implement operational performance step-change and significantly enhance asset value through extension of economic field life. Typically, the opportunity to implement change occurs upon transition of asset ownership from one oil company to another. In this regard, the services Petrofac provides to its clients include: asset transition planning and execution, including improvement in the crewing and management of oil and gas production installations; and data room and due diligence services for clients pursuing asset acquisitions. Drawing on the expertise of the Group s engineering and consulting services business, Petrofac also provides specialist engineering services including brownfield studies, detailed engineering, construction services and commissioning services, to support Operations Management contracts and to pursue external business. Petrofac is the leading outsourced oil and gas process facilities manager in the UKCS, having been awarded five of the six duty holder contracts so far granted to contractors to manage facilities in the UKCS. Petrofac s clients, who are operators of installations in the UKCS, operate under production licences from the DTI, and have overall responsibility for maximising the reserves extracted, establishing and maintaining a safe operating regime, preventing environmental damage and decommissioning. However, these operators may contract certain of these duties to third parties. Petrofac manages the operation of offshore and onshore facilities on behalf of those operator clients which have chosen to outsource this activity. Petrofac has thereby been at the forefront of the transition in the UKCS whereby independent oil companies have entered the UKCS in place of the major oil and gas companies. The Operations Management service offering supports these new entrants into the UKCS and the subsequent growth of their asset portfolio. Petrofac has an established portfolio of managed facilities in the UKCS comprising the Northern Producer on the Galley field, Montrose and Arbroath platforms, Greater Kittiwake assets, Hewett offshore facility and Bacton Terminal, Schooner and Ketch platforms, Horne and Wren platforms and Heather and Thistle platforms. Brief details of certain of the contracts relating to such facilities and platforms are set out in Contracts below. Responsibility for operating a facility brings with it the responsibility for establishing and maintaining a safe operating regime, and under the relevant safety regulations, Petrofac, as facility manager, is known as the duty holder. For further information on Petrofac s regulatory obligations as a duty holder, please see paragraph 5 of this Part III. Since the Facilities Management business was established by the Group in 2002, it has accelerated its service provision outside the UKCS with new contracts in Kuwait, Iran, Papua New Guinea and Sudan. To date, the nature of the facilities management work secured outside the UKCS has largely been Operations Support. Clients The client base of Petrofac Facilities Management for the provision of its managed operations services has historically been the growing number of smaller independent oil and gas companies in the UKCS, due to their high propensity to outsource. Such clients include Paladin Expro Limited (Paladin), Venture Production (North Sea Developments) Limited (Venture), Tullow Oil UK Limited (Tullow) and members of the Lundin group. Petrofac also provides its operational support services to major oil companies, including Hydrocarbon Resources Limited (HRL), BHP Billiton Limited (BHP Billiton), BG Exploration and Production Limited, BP, ExxonMobil Corporation, Marathon, Total E&P (UK) Limited (Total), Kerr-McGee North Sea UK Limited and Canadian Natural Resources Limited (CNR). In recent years, Petrofac has entered into operations maintenance contracts with two major national oil companies: KOC and South Pars Gas Company, a subsidiary of the National Iranian Gas Company (SPGC). 42

43 Contracts The Facilities Management business is, in general, long term contract based, and contracts are typically cost reimbursable with an element of performance related remuneration. The majority of contracts either include a schedule of rates or a fee based remuneration structure. The UKCS life of field duty holder contracts have limited provision for serving without cause termination notices. The international contracts of the Facilities Management business contain a wider variety of terms. Examples of contracts on which the Facilities Management business is currently working include: Lundin (Heather and Thistle platforms) turnkey facilities management From 1 May 2005, Petrofac has taken over responsibility for the management of the Heather and Thistle platforms for Lundin. The contract is on a life of field basis. Petrofac acts as turnkey facilities manager (providing operations and maintenance management) and safety case duty holder of the Heather and Thistle platforms. Petrofac also undertakes significant brownfield engineering and construction activity under this contract. The value of the contract on announcement was US$250 million. Talisman (Galley) turnkey facilities management Under a contract renewed in February 2005, Petrofac is responsible for the management of the Northern Producer floating production installation on the Galley field. The original contract was entered into in October Under a contract with Sea Production Limited, which in turn contracts with Talisman (the owner of the field), Petrofac acts as facilities manager (providing operations and maintenance management) and safety case duty holder. Petrofac is also responsible for the onshore and offshore operations teams and provides facilities engineering support. The contract lasts until June The value of the contract on announcement was US$26 million. Venture (Greater Kittiwake Area) turnkey facilities management On 26 November 2003, Petrofac entered into an agreement with Venture to act as facilities manager in relation to its assets in the Greater Kittiwake area of the UKCS. Petrofac acts as turnkey facilities manager (providing operations and maintenance management) and safety case duty holder. The contract lasts for five years, with two two-year optional extensions at the client s option. The value of the contract on announcement was US$64 million. Tullow (Hewett offshore and Bacton onshore terminal, Schooner and Ketch platforms, Horne and Wren platforms) turnkey facilities management On 1 October 2003, Petrofac took over responsibility for the management of Tullow s Hewett facility in the Southern North Sea and its Bacton gas terminal in Norfolk. The agreement marked the first time that a facilities management company had assumed management as duty holder of an onshore gas terminal in the UK (Bacton). Petrofac acts as turnkey facilities manager (providing operations and maintenance management) and safety case duty holder for the Hewett field and COMAH Report holder for the onshore gas terminal at Bacton. The contract is on a life of field basis. On 31 March 2005, Tullow awarded additional contracts to Petrofac for the support of its (normally unmanned) Schooner, Ketch and new Horne and Wren assets. These contracts are also on a life of field basis. Paladin Expro (Montrose and Arbroath platforms) turnkey facilities management On 20 May 2003, Petrofac entered into an agreement to act as facilities manager for Paladin in relation to the Montrose and Arbroath platforms. Petrofac acts as safety case duty holder and provides turnkey facilities management (operations and maintenance management). The contract is on a life of field basis. Petrofac s role was broadened in 2004 to include brownfield engineering capabilities and to manage Paladin s supply chain activities in support of its drilling and capital development projects. Total (Alwyn and Dunbar platforms) operations and maintenance contract On 17 January 2005, Petrofac agreed a contract to provide operations and maintenance personnel onboard platforms and in the client s onshore offices for Total s Alwyn and Dunbar facilities. The contract lasts for five years with an option to extend for a further two years. The value of the contract on announcement was US$70 million. 43

44 BHP Billiton (Liverpool Bay platforms) operations, maintenance and construction contract On 1 December 2004, Petrofac was awarded a five-year extension of its contract with BHP Billiton in relation to the Liverpool Bay Assets located in the Irish Sea. The contract is for the provision of maintenance personnel onboard offshore platforms and the ad hoc supply of personnel to the client s onshore facilities, together with a full range of engineering and construction services. The contract is an extension of the parties original 10-year contract entered into on 22 February The Liverpool Bay development comprises the Douglas and Lennox platforms, an oil storage installation and the onshore gas processing terminal at Point of Ayr. The value of the contract on announcement was US$114 million. Kuwait Oil Company (KOC), Kuwait Maintenance management contract Under a contract awarded on 15 March 2005 by KOC, Petrofac is responsible for the provision of maintenance management and full maintenance services, of various facilities in North and West Kuwait areas comprising oil gathering centres, gas booster stations, gas steam and water injection plants, water gathering and pumping stations, gas and crude oil pipelines and well heads. The services include maintenance management and technical support, corrective and predictive maintenance, engineering services, the provision of spare parts for control and shutdown systems and training of personnel. The contract lasts for five years with a one year extension at the client s option. The value of the contract on announcement was US$125 million. Greater Nile Petroleum Operating Company (GNPOC), Sudan maintenance contract On 1 April 2004, Petrofac entered into a contract with GNPOC in relation to its power plant and pipeline facilities in Sudan. Petrofac is responsible for maintenance management and technical expertise regarding maintenance of operating assets. The contract lasts for three years with a one year extension at the client s option. The value of the contract on announcement was US$40 million. South Pars Gas Company (SPGC), Iran maintenance and operations contract On 1 March 2004, Petrofac entered into a contract with SPGC, a subsidiary of the National Iranian Gas Company, for maintenance, modifications and operations on the South Pars Phases 1 and 2. The contract lasts for three years with a two year extension at the client s option. During 2004, the contract was extended to include the provision of further logistical support to additional Phases. Interoil, Papua New Guinea commissioning and facilities management On 9 November 2003, Petrofac entered into a contract with Interoil Corporation in relation to the Napa Napa refinery in Papua New Guinea. Under the contract Petrofac was responsible for the pre-commissioning and commissioning of the refinery whilst it was under construction, and subsequently for the total management of the day to day refinery operations, maintenance and production. Competitors Petrofac s competitors for facilities management in the UKCS include Wood Group, Aker Kvaerner ASA, Amec and the KBR group, and a number of specialist providers of operational support services. Its international competitors include Amec, KBR, Vetco International, Wood Group and Worley Parsons. Petrofac also competes with the in-house ability of oil and gas companies to manage and support their own facilities. Training Petrofac Training provides training and training management solutions to the oil and gas industry on a worldwide basis. In order to work offshore in the UK, certain safety training qualifications are required. The UK Offshore Operators Association (UKOOA) has created guidelines that oil and gas operators should adhere to regarding emergency response training. COGENT, the industry managed training regulator in the UK, has also created and accredited training standards, which Petrofac delivers. One such mandatory training course is the Basic Offshore Safety induction and Emergency Training (BOSIET) course, which is regarded as the minimum requirement for travelling and working offshore. As Petrofac is involved in the provision of many of these required 44

45 core safety training courses, Petrofac Training has a regular demand for its approved courses. Petrofac also provides a range of skills-based training and assessment. Petrofac offers blended learning, combining structured learning with practical development and assessment. Its four key product streams are: Safety training through the well-known RGIT Montrose brand RGIT Montrose was originally established as an industry-wide training centre, and has been operating for over 25 years. Petrofac offers survival courses, basic offshore safety induction, emergency training, helicopter underwater escape training and fire training courses. The regulatory requirement to have completed safety training before working offshore generally means that Petrofac s business in this area is regular and also consists of a considerable proportion of repeat business. Operations and technical training and consultancy Petrofac provides skills-based training and assessment for production, operations, maintenance and well services disciplines. Such training ensures that offshore workers are certified to industry-standard levels of competence in order to perform their services offshore. Petrofac also provides advice on all safety and skills training areas in relation to systems and safety case development, risk assessment and management, accident and incident investigation and HSE audits. Support and management services, including Training Management Solutions Turnkey training solutions offer a single solution for oil companies seeking to train their employees in skills and safety courses. Petrofac provides comprehensive training solutions for the management and administration of all a client s training requirements, which may involve providing certain in-house training itself and/or arranging for the delivery of additional third party training. An example is the Company s management of Shell s offshore training requirements in the UK, the Netherlands and Norway. Training solutions can also incorporate the design, establishment and running of a training centre owned or leased by Petrofac and where the training programmes would be provided by Petrofac. An example is the Caspian Technical Training Centre, in joint venture with TTE International. Emergency response and critical incident management through the Rubicon Response brand Petrofac Training offers training and consultancy in relation to dealing with emergency situations, including courses on major emergencies, crisis management and incident control. With a professional team of more than 200 people, Petrofac Training operates out of centres established in the UK (Aberdeen, Montrose and Dundee), in the Caspian (Baku), the United States (Lafayette, Louisiana) and Trinidad (Port Lisas) with additional offices in Sharjah, UAE, Houston, Texas and Kuala Lumpar, Malaysia. Petrofac Training trains over 30,000 delegates annually, and has provided training and consultancy in over 26 countries. Petrofac Training now has a presence in, or access to, capability in all of the major oil and gas regions worldwide and a leading depth of knowledge and ability in safety and skills training and development. It is highly regarded in the oil and gas industry for practical fire-fighting and survival training and technology skills training. Clients Petrofac Training s clients for its safety and technical training in the UK include many of the UK s oil and gas operators and contractors. The clients of its international training business include BP Sharjah and ENI Iran. Clients of its turnkey training solutions business include Shell Exploration and Production Europe Limited (Shell) and Total. In addition, Petrofac Training s clients also include individual clients and a number of organisations arranging ad hoc training courses for their employees. Petrofac Training also provides in-house training to Petrofac s own employees. Contracts The Petrofac Training business is driven by a large number of short term and short lead time contracts. Petrofac Training generally contracts under its standard terms and conditions of service for calendar course provision and short-term project work. It offers over 150 different calendar courses. Larger projects, especially those involving infrastructure, are usually negotiated and may include a longer-term contract. 45

46 Examples of contracts on which Petrofac s training business is currently working include: TTE International Caspian Technical Training Centre Following the successful completion of a design-and-build contract for a BP-led consortium s training centre in Baku, Azerbaijan, Petrofac (in joint venture with TTE International) was awarded a three-year management and operations contract on 1 January 2004, to include the provision of training centre staff and the supply of consumables and curriculum materials. In May 2004, the Caspian Technical Training Centre was opened. Based at the Sangachal Terminal Expansion Project area, the centre has a capacity to train 400 operations and drilling technicians a year to full international standards. The contract lasts until 1 January 2007, with the possibility of two one-year renewals at BP s option. Shell Exploration and Production Europe Petrofac provides comprehensive offshore training management solutions to Shell, covering its three key European operating centres of the UK, the Netherlands and Norway. The initial contract commenced in January Petrofac Training successfully gained a two-year extension of the contract in May 2005, together with two further one-year optional extensions, at Shell s option. BP Sharjah BP Sharjah Oil Company awarded Petrofac Training the contract to provide and manage its HSE training provision for three years from 1 April Theoretical and practical HSE training is provided to BP Sharjah delegates at the Petrofac facilities in Sharjah and the BP Sajaa plant at Sharjah. Petrofac is also responsible for the training co-ordination, planning and scheduling and maintenance of training records. ENI Iran Petrofac Training has a contract with ENI Iran to provide theoretical and practical HSE training at ENI s facilities in Iran. The contract was entered into in June 2005, and is a call off contract against a client s specified budget. Competitors Competition in the training market is more fragmented compared to the markets for Petrofac s other services. Competition in the provision of training management solutions comes from ASET and Nutec (part of the Global Safety Group). There are a number of independent operators which compete with Petrofac in the provision of certain of its training courses, including for example, The Fire Service College in Moreton-in-Marsh, England in relation to the provision of fire training services and Amec for technical and competency training. Petrofac also competes with the in-house ability of the oil and gas companies to manage and provide training to their own employees. Competitive strengths of the Operations Services Division The Directors believe that the competitive strengths of the OS Division include the following: Petrofac is the leading independent provider of turnkey facilities management in the UKCS The Directors believe that the UKCS is one of the world s most advanced markets in operations outsourcing. Petrofac s leading position is recognised throughout the industry Petrofac has secured five of the six duty holder contracts that have to date been awarded to contractors in the UKCS covering 16 out of the 17 offshore installations operating under such arrangements. Petrofac has demonstrated its competence at performing the duty holder role with its clients. Petrofac has also developed credibility and an effective relationship with both the H&S Executive and the DTI. Petrofac has a focus on efficient operation of marginal and mature oil and gas fields in the UKCS. It is well placed to combine its UKCS expertise with the international reach of the E&C Division to create a platform for international expansion. Petrofac has established client relationships and a track record internationally through its EPC business as well as recent OS Division contracts. The Directors believe Petrofac is well positioned to grow its international OS business, being well regarded in the market as having expertise in operating 46

47 in the Middle East, North Africa and the FSU. The Directors also believe Petrofac s established relationships with certain NOCs in these regions is a competitive strength. Petrofac has an established track record of facilities performance improvement Petrofac has demonstrated strong capabilities in implementing performance step-changes in asset ownership transitions. Petrofac has improved volumetric efficiency, reduced operating costs and improved production uptime under certain of its facilities management contracts. Petrofac provides from a single source a range of specialist and value-added services Offering specialist services, for example, machinery management or operational effectiveness audits on platforms, broadens the range of services offered by Petrofac. By developing new and innovative services, Petrofac is able to expand the range of services offered to its clients and increase the value added to the management and operation capabilities offered. Petrofac has a strong safety track record Petrofac s commitment to high health and safety standards is reflected in its historic track record in safety. In recent years, Petrofac has consistently ranked in the top quartile of safety performance in the UKCS, when measured against its competitors or against the operating oil companies, as measured by UKOOA. Petrofac is an associate member of UKOOA in the North Sea and its safety performance is measured regularly against its operating oil company peers. Petrofac has developed an effective relationship with the H&S Executive as duty holder with responsibility for safety management on the platforms it manages. Health and safety credibility is a critical element to winning new business as a duty holder in the UKCS, particularly as many smaller independents may not have a comparable safety record. Petrofac s strong safety record puts it in a good position to win new business and to consolidate its business with existing clients. Petrofac s training in practical fire-fighting, survival training and emergency response training is long established and highly regarded by the industry RGIT Montrose was established as an industry-wide training centre and has been operating for over 25 years. RGIT Montrose is a well regarded oil and gas safety training brand. This strong brand awareness gives Petrofac a good position on which to develop its business. The halo effect associated with Petrofac s safety training excellence gives Petrofac additional credibility when offering to take on the management of a platform for oil companies. As a duty holder for 16 offshore installations, and COMAH Report holder for one onshore terminal, Petrofac provides a full emergency response capability which is comparable to that provided by the major operating oil companies. This service has been extended to provide standalone emergency response services to three Amerada Hess facilities, for which Petrofac is not the duty holder. This emergency response capability has recently been launched as an independent service to the North Sea industry seeking to substitute the several oil company specific, part-time, response teams with a fully staffed, professional service integrated with coastguard, police and oil spill response services. Petrofac has successfully blended oil company and contractor skill-sets, giving it an informed industry insight and allowing it to anticipate client needs. A relatively high proportion of Petrofac s senior personnel have significant experience of working for major oil companies. Combined with the experience of those team members with a contractor-based background, this gives Petrofac an informed industry insight, allowing it to anticipate client needs. Resources In selected situations, the Resources Division invests alongside its clients and partners in producing and proven or probable but not fully developed oil and gas reserves and energy infrastructure. Investments are assessed on the basis of their projected financial return reflecting the anticipated risks of the investment and, independently, the opportunity for the Group to provide services to its clients and partners. 47

48 This business is based in Sharjah, UAE; Kuala Lumpur, Malaysia; and London, England and employs 36 business development employees including petroleum engineers and other technically trained personnel with a further 150 employees involved in the operation of a refinery investment in Kyrgyzstan. In FY 2004, the Resources Division s external revenue was US$45.0 million with net profit of US$7.0 million, representing 5 and 15 per cent. respectively of the Group for that period. In H1 2005, the Resources Division s external revenue was US$22.6 million with net profit of US$12.0 million representing 3 and 33 per cent. respectively of the Group for that period. At 30 June 2005, the Group s investments had a book value of US$96.6 million. Industry outlook Current and expected levels of oil and gas prices typically have a direct effect on the cash flows generated and returns earned from upstream oil and gas investments. As a result, higher oil and gas prices typically increase the level of expected returns for upstream investments. The major integrated oil companies grew significantly in scale during the 1990s as a result of consolidation. Partly as a result of the increased scale of these sector participants, there has been a trend for them to divest their smaller scale fields in order to concentrate their development and management resources on larger developments. The Directors believe this trend provides increased opportunities for the Resources Division to invest in high-quality upstream assets. In addition, the Directors believe that Petrofac has a competitive advantage in developing and operating such fields in a cost effective manner, based upon the experience and knowledge housed within its E&C and OS Divisions. Since the mid 1990s, many of the world s major national and independent oil and gas companies have been increasingly outsourcing their global maintenance, modification and operations service requirements. Outsourcing is often viewed as a compelling alternative by producers who recognise that it allows them to focus on their core competencies, enhance their safety performance and reduce costs. The Directors believe that clients who have contracted with Petrofac s E&C or OS Divisions may seek to align Petrofac s economic interests with their own by having Petrofac co-invest in certain projects. Conversely, when Petrofac s Resources Division makes a minority investment in an asset, the Directors believe this will result in increased opportunities for Petrofac s E&C and OS Divisions to provide services to the asset. Investments in oil and gas reserves The Resources Division s investments in producing and proven or probable but undeveloped reserves would include, for example, participation in large onshore field developments, onshore and offshore field developments that major oil companies may consider to be marginal, and late life producing assets, particularly those offshore. Large field developments can depend on the ability to cap EPC and or operations and maintenance costs if they are to be developed effectively. With the benefit of the Group s wider service offering, opportunities to provide this service, coupled with equity investment, are a target area for the business of the Resources Division. The operatorship of many smaller undeveloped fields is often held by the major oil companies. However, in comparison to other development opportunities and the need to replenish reserves, these smaller fields may not be regarded as having sufficient scale by their current owners. Typically, such assets undergo transition of operatorship, and possibly ownership, and through participation in this process, the Resources business can catalyse the development of these assets using the focused skills of the wider Petrofac Group. The opportunity to invest in, and further develop, late life or mature assets in order to enhance remaining production generally cannot provide the relative economic justification to merit the attention of the major oil companies. These types of investment would typically be made by acquiring an interest in a production sharing contract (PSC) or risk service contract (RSC), under which the investment return is earned through monetisation of partners entitlements to the hydrocarbons lifted. In certain circumstances, such 48

49 investment might mean that Petrofac becomes the licence operator of that asset, as is the case with the Cendor investment in offshore Malaysia. When disposing of interests in late life assets, vendors will often seek to transfer their liability for decommissioning. Whilst the Resources Division will consider opportunities to take over such assets on a case by case basis, Petrofac would only be likely to accept decommissioning liability if it can establish that the risks are well understood and manageable, and that there are appropriate mechanisms in place to mitigate against such risks. Certain investment opportunities may require the Resources Division to commit to limited exploration expenditure. The strategy of the Resources Division in this regard is to ensure that any such expenditure constitutes only a minor part of the wider investment opportunity; furthermore, Petrofac looks to defer, where possible, such expenditure until an investment is providing satisfactory cash flow and may also seek to finance the investment through a farm-in and carry arrangement. Investments in assets may include reservoir appraisal expenditure, for example the cost of drilling a limited number of additional wells on known hydrocarbon structures. Because Petrofac does not take pure exploration risk except on an upside basis above its base case return requirements, it is therefore able to capitalise on its investments relatively more quickly compared to investments that rely on exploration success. Investments in energy infrastructure Petrofac s investments in oil and gas midstream and downstream infrastructure would include, for example, refineries, pipeline transmission, tolling process plants and utilities, and comprise both investment in greenfield facilities or acquisition of existing brownfield facilities. These types of investment would typically be structured either as the direct acquisition of an asset or a variety of turnkey project development structures, including Build Operate Transfer (BOT), Build Own Operate Transfer (BOOT) and Build Own Operate (BOO) development arrangements with the local government or national oil company where the asset is domiciled. Petrofac has entered into an alliance with First Reserve, a US private equity fund, to co-operate on certain midstream and downstream infrastructure investments in North Africa, the Middle East and Central and Eastern Europe. The alliance brings together Petrofac s project identification and assessment capabilities with First Reserve s financing and transaction structuring expertise. Petrofac has also entered into an alliance with Cal Dive to pursue opportunities jointly in mature offshore oil and gas properties and proven undeveloped reserves in the UKCS. The alliance brings together Petrofac s engineering and operational track record in the UK with Cal Dive s GoM experience in marine contracting and particularly decommissioning. The alliance s strategy is to operate mature fields and offer the capability to manage and carry out decommissioning as required. Business development The business development team of the Resources Division comprises highly qualified personnel with technical, operational, asset investment and asset management backgrounds, typically gained in major oil companies. A key differentiating feature of the Resources business is the business development team s combination of skills, which enable the Group to make a rapid, informed assessment of investment opportunities. In carrying out its business, the team undertakes opportunity identification, project technical, economic and risk analysis, contract negotiation, structured financing, government and regulatory liaison, contract management and asset management. The Resources business leverages the expertise of Petrofac s E&C and OS Divisions to optimise development and operational costs and to provide combined development and operational solutions where needed. Following investment, the team s operational background provides the necessary expertise to manage an asset s development, procuring the services of the wider Group where appropriate. 49

50 Principal investments Details of the principal investments of the Group for the 2002, 2003 and 2004 financial years and for the period between 1 January 2005 and 19 September 2005 (the latest practicable date prior to the publication of this document) are set out below. With the exception of the Ohanet project, which was part financed through external project finance, all the investments referred to below have been financed through Petrofac s own cash resources. At 30 June 2005, the total book value of investments was US$96.6 million with the Ohanet and Cendor projects representing 87.0 and 9.5 per cent. respectively of the total. Ohanet, Algeria Petrofac Resources largest investment is in the Ohanet project in Algeria. In a joint venture with BHP (as operator), Japan Ohanet Oil & Gas Co., and Woodside Energy (Algeria), Petrofac invested in excess of US$100 million for a 10 per cent. share in an RSC with Sonatrach, Algeria s national oil company. The investment commitment was made in July The US$1 billion Ohanet development is located in the Illizi province of Algeria, south-east of Algiers and close to the Libyan border. The development phase consists of a 3D seismic programme over the entire Ohanet contract area, the drilling of 32 new wells and the re-completion of 15 existing wells, a gas gathering system comprising over 150km of flowlines, a two train wet gas treatment facility and export to the Sonatrach pipeline network. Petrofac s E&C Division carried out the EPC contract for the gas processing facilities of Ohanet in joint venture with ABB Lummus, worth a total of approximately US$600 million (with Petrofac having a 50 per cent. share). The Group s OS Division was also responsible for part of the onsite commissioning works. The Directors believe that Petrofac s ability to draw on its service capabilities know-how and demonstrate to BHP Billiton how capital costs could be reduced placed the consortium in a competitive position to win the bid. First gas for export began flowing in late October 2003 with production increasing into During 2004, the Ohanet development produced, on average, approximately 450 million standard cubic feet per day of dry gas for export, approximately 23,900 barrels per day (bpd) of condensate and approximately 1,800 tonnes of liquefied petroleum gas (21,200 bpd of oil equivalent). Under the terms of the RSC, signed in July 2000, Petrofac and its joint venture partners (the Ohanet Consortium) receive a portion of the Ohanet liquids production over an 8 to 12 year period, depending on hydrocarbon price and production levels, commencing in October The pipeline sales gas and its associated revenue is owned and marketed by Sonatrach. Production operations are managed by a joint BHP/Sonatrach operating company. The RSC entitles the Ohanet Consortium to an in-kind payment comprising three components: (i) repayment of investment, (ii) a remuneration payment providing a defined uplift on the investment, and (iii) re-imbursement of its share of the agreed-upon operating costs (the Ohanet Consortium is entitled to recover Sonatrach s share of the operating costs during the month immediately following the month during which costs were incurred). The Ohanet Consortium s annual revenue is capped at 49 per cent. of the total production (including the gas) by weight measured in tonnes of crude oil equivalent using agreed conversion factors. If there is insufficient revenue to pay the Ohanet Consortium in any month due to insufficient liquids production, low price or the revenue cap, the Ohanet Consortium can recover any costs not repaid in any month, in the next or subsequent months. Because this remuneration is in-kind, the repayment period is a function of production levels and prevailing hydrocarbon prices. The initial recovery period is set at 8 years. If production levels or prices for the products drop such that recovery is not attained within the 8 year period, the period can be extended for an additional three years. Finally, if recovery is not achieved within the 11 year period, and if the average benchmark Brent prices during the 11 years had averaged below a minimum level, then the period would be extended for a final (12th) year. 50

51 The monetary value of the hydrocarbon liquids delivered to the Ohanet Consortium are determined on the basis of sales prices realised by Sonatrach in export transactions. At Petrofac s current base case production profiles, the benchmark Brent prices would need to average below US$24/bbl from 30 June 2005 to extend the repayment period beyond 8 years. If prices are US$15/bbl average from June 2005, the repayment period will extend to 11 years. Average prices would need to be below US$10/bbl from June 2005 to enable an extension into a final year of recovery. Each member of the Ohanet Consortium has appointed an affiliate of BHP, BHP Trading and Marketing (BHP T&M), to market the hydrocarbons based on a separate marketing agreement. Under this agreement, BHP T&M is authorised to market each partner s share of the hydrocarbons on an exclusive basis. BHP T&M s obligations under the marketing agreement are guaranteed by BHP. Further, BHP T&M is also authorised to sell all the hydrocarbons to Sonatrach under the terms of a separate sale and purchase agreement between Sonatrach and BHP T&M. The investment commitment was made at a time when prevailing oil prices were at approximately US$20 per barrel. In the current environment, with relatively high oil prices, the Ohanet Consortium s entitlement is typically achieved within the first two weeks of each month. Sonatrach is liable to pay a royalty and all taxes applicable under Algerian law with respect to the entire production coming from the Ohanet project. All decisions relating to the management and execution of the RSC are taken by unanimous vote of a management committee comprising four members from Sonatrach with the Ohanet Consortium appointing a further four members. The chairman of the management committee is a Sonatrach representative and the vice-chairman is a representative of the Ohanet Consortium. Algerian law requires foreign companies with interests in partnerships for the prospection, research and exploitation of liquid hydrocarbons in Algeria to make certain notifications to the Ministry of Energy and Mines concerning changes affecting control of their companies. Examples of these requirements include information concerning holdings of more than 10 per cent. of the foreign company s corporate capital and concerning any transaction as a result of which one or more individuals or corporate entities may lose a determining power in the direction or management of the foreign partner company. If any measure or transaction were to result in other individuals or corporate entities obtaining a determining power in the direction or management of the partner company, the Ministry may within three months following receipt of the relevant information, notify the foreign partner that such measure or transaction is incompatible with maintaining the approval of any protocol, agreement or contract concluded with the State and the national company and may require termination of the partnership. The circumstances of the Offer require notification to be given, and such notification has been given to Sonatrach and will be given to the Ministry following Admission, but the relevant provisions of Algerian law do not provide a process for determining whether or not the Offer will result in any individual or corporate entity obtaining any determining power in the direction or management of Petrofac so as to result in any such right of termination arising. The Board considers that the Offer will not result in such a termination right arising; however, BHP has reserved its position in full until it receives confirmation that this is the case. Cendor PM304, Malaysia In May 2004, Petrofac Resources acquired the Amerada Hess subsidiary which owns and operates a 40.5 per cent. interest in the PSC for the undeveloped Cendor field offshore Peninsular Malaysia in Block PM304, and has subsequently reached agreement with PetroVietnam Investment Development Company (PIDC) for the sale to PIDC of a 10.5 per cent. interest. The field will be developed in phases by a Petrofac-led, joint operating team with Petronas Carigali, Kuwait Foreign Petroleum Exploration Company and PIDC. Drawing on the skills within the Group s E&C and OS Divisions, the Petrofac-led team submitted the partner approved proposed field development plan (FDP) in February 2005 and gained regulatory approval from Petronas in May. The major contracts for the development are now in the process of being let. Ryder Scott, an independent reserves consultant, estimates proven reserves of 51

52 the field to be approximately 24.6 million barrels and proven plus probable reserves of approximately 30.3 million barrels. For further detail on this report, please see Part VII Competent Person s report by Ryder Scott. The Directors believe that the Group s OS Division will be closely involved with the facilities management of the platform upon start up of production. The Directors believe that offshore Malaysia offers a number of additional opportunities for Petrofac to replicate its combined approach of investment, asset development and operations management in monetising proven undeveloped discoveries. Hewett, UKCS In August 2005, Petrofac Resources agreed to acquire Centrica s per cent. interest in the Hewett gas field in the UKCS. Completion of the acquisition is subject to the approval of the Hewett partners and the DTI, currently expected to be received in late Under the terms of the alliance Petrofac has with Cal Dive described above, Petrofac will offer Cal Dive the right to acquire half of Petrofac s interest in the field, subject to the approval of the Hewett partners and the DTI. Originally discovered in 1966, Hewett is a mature gas field and has produced over 3.4 trillion cubic feet of gas to date. There are 6 platform structures in the field complex, which deliver gas into the Bacton terminal on the east coast of England. Petrofac s OS Division currently acts as service operator and duty holder for the Hewett area fields and COMAH Report holder for the Bacton terminal on behalf of Tullow, the licence operator. The Directors believe that alignment between Petrofac and the other field owners will be enhanced by Petrofac s participation as an equity holder. In addition to continued improvement in operating cost efficiencies, developing new transportation business and reinvesting in the fields will be key to extending the commercial life of the facilities. The Directors believe gross reserves to be 35 billion cubic feet for the area and that production in 2005 is averaging approximately 33 million cubic feet per day (7.7 million cubic feet per day net sales gas to Petrofac Resources). Third party gas from the Thames and Lancelot fields is also processed through the Bacton terminal. At completion, Centrica will pay Petrofac Resources 4 million and transfer certain plant and machinery allowances with the asset. The economic date of the transaction is 1 January Petrofac Resources will be required to provide Centrica with a letter of credit to cover the decommissioning liability which is presently estimated at 20 million net to Petrofac (on the basis of its current ownership of the per cent. interest). Although decommissioning is currently estimated to occur in 2010, Petrofac Resources will be reviewing strategies alongside its partners to extend the life or look at alternative uses of the Hewett area assets. Kyrgyz Petroleum Company, Kyrgyz Republic Petrofac Resources owns a 50 per cent. interest in Kyrgyz Petroleum Company (KPC), a company engaged in the production and refining of crude oil and the marketing and sale of oil products in the Kyrgyz Republic. KPC is jointly owned by Petrofac and Kyrgyzneftegaz, the state-owned oil and gas company in the Kyrgyz Republic, and is the only integrated oil refiner and distributor of petroleum products in the country. Petrofac has managed KPC s facilities and operations since 1998, having completed the design and construction of the facility. KPC now employs around 150 technical specialists and support personnel who, after a major training programme instituted by Petrofac, are now almost entirely Kyrgyz citizens. Cragganmore, UK North Sea In January 2004, Petrofac Resources acquired a 5.58 per cent. interest in Block 9/28a Area B in the UK North Sea. The block contains the Crawford field, since renamed Cragganmore, which was originally developed by Hamilton Oil and Gas (now BHP Billiton) using a converted semi-submersible production vessel. Petrofac Resources is in partnership with Tuscan Energy, as operator of the field, Acorn Oil and Gas and Stratic Energy. The field is being remapped using up-to-date data processing and interpretation methods. A number of development options are being evaluated together with a prospect inventory of additional appraisal targets. Petrofac s decision to partner was based on the prospect of services being provided by the Group s E&C Division and ultimately by its OS Division. 52

53 Elke, UKCS In May 2004, Petrofac Resources acquired a 100 per cent. interest in the Block 28/3 in the UKCS, containing the Elke field. The Elke field was discovered in 2002 by OMV and contains approximately 227 million barrels of heavy oil initially in place. However, due to the low API gravity of the oil, the field remained undeveloped by OMV and its original partners. Developing an offshore field with low API gravity oil requires an innovative development scheme and Petrofac is looking to draw on the expertise of its E&C and OS Divisions with a view to providing an economic FDP. If successful, the approach may have application to other offshore heavy oil fields. Save as disclosed above and other than continuing capital investment requirements of the investments outlined above, the management bodies of the Petrofac Group have not made any firm commitments on any principal future investments which are material to the Petrofac Group as a whole. Competitors The Resources Division faces competition from the following diverse groups: oil and gas companies which compete for equity participation in projects. This is particularly prevalent in the upstream arena; mezzanine and debt financiers of projects, which can obviate the need for further equity participation; for example, certain Japanese trading house financing arms, working with engineering partners, can be either competitors or partners. Pipeline projects are typically contested by local engineering and construction companies along with finance groups; and certain Chinese and Indian oil companies which have close ties to low cost national engineering companies or internal EPC arms which often compete, particularly on downstream projects. Competitive strengths of the Resources Division The Directors believe that the competitive strengths of the Resources Division include the following: An experienced and high calibre project development team provides rapid evaluation, execution and financing of project opportunities, together with project management and financing capabilities to support implementation The Petrofac Resources team has multi-disciplinary capabilities and analytical and technical strengths and includes a number of petroleum engineers. Alongside the investment analysis and execution capabilities, the personnel are very well informed in the services related to asset management and evaluation, and are able to understand and shape the performance of the assets. The Petrofac Resources development team can also leverage the expertise within the rest of the Petrofac Group. Petrofac is able to draw on client relationships, know-how and service expertise within the wider Group to enhance identification, evaluation and completion of investments The Resources Division makes investments with the benefit of the broader Group s expertise in relation to the development of a project across the asset s life cycle. By accessing these design, construction and operating capabilities, the Resources Division can more effectively evaluate the scope and risks involved and develop, shape and create value in those projects it is investing in. High level business contacts established by the Resources Division can create new business opportunities for the rest of the Group. The business development team in the Resources Division forges relationships and establishes contacts with senior personnel in the process of negotiating and finalising investments. Petrofac s other two divisions can draw on these contacts with a view to establishing new business opportunities through high level contacts. 53

54 Ability to assess completion and process performance risk when structuring investments eases financing requirements On entering into oil and gas infrastructure investments, Petrofac s E&C and facilities management expertise provide it with the ability to assume, on a case by case basis, the risk for performance and completion of the project. Such risk would be taken on for those parts of the project which Petrofac is dealing with in-house which would be subject to its standard assessments, including risk assessment. This effectively allows Petrofac to offer a performance wrap to its investment proposal which may be attractive to certain partners. Track record in challenging countries Petrofac has successfully invested in projects in Algeria at a particularly politically unstable period (the Ohanet project) and in a remote area of Kyrgyzstan (through its investment in KPC). Both projects demonstrate its ability to undertake investments notwithstanding challenging geo-political conditions. The investment in KPC has helped to generate a local oil industry in the country and the majority of the personnel working on the project are now Kyrgrz nationals, having been trained to high standards under a training programme instigated by Petrofac. 5. Health, safety and the environment (HSE) and security Petrofac sets high standards of health and safety for itself, its staff and its sub-contractors. It also recognises that a responsible strategy to manage environmental issues affected by its business is essential to its employees, its clients and society. Group policies The Group has developed its own health and safety policies that are adopted by each of the Group s divisions, adapted, where applicable, for that business unit s particular scope of operation. The Group is committed to continual improvements in its environmental performance, to the prevention of pollution, and to full compliance with relevant environmental legislation and other requirements. HSE matters are considered at each regular meeting of the Board, with performance, programme and opportunities for improvement being the main items for discussion. Each division has its own programme of HSE audits and reviews. In addition, the Corporate Safety function, under the direction of the Corporate Safety Director, performs an annual independent HSE review. These reviews identify performance issues and measure compliance by the divisions with the Group s HSE policies and standards. The results of this report are reported back to the Board. Health and safety incidents With respect to incident reporting, Petrofac has adopted the American Occupational Safety and Health Administration (OSHA) guidelines and definitions, as being most applicable to the Group s principal geographic areas of operation and clients. However, the UK system for the Reporting of Injuries, Diseases and Dangerous Occurrences Regulations (RIDDOR) is operated in parallel to meet local legislative requirements for UKCS operations. Each business unit reports monthly at divisional board level on any health and safety incidents that have occurred that month. At each regular Petrofac Board meeting, all incidents in the OSHA recordable category are identified and reviewed to establish trends. All Lost Time Injuries (LTIs) are required to be identified and discussed in detail to assure the Board that the appropriate lessons have been learned and implemented. All LTIs are required to be reported promptly to the executive Directors and Divisional Chief Executives. In addition, the Group sets KPIs for health and safety incidents and again, at the divisional board meetings, performance against these KPIs is reviewed. Approximately 130 million man-hours have been completed or managed from January 2002 to date. During 2004, approximately 39 million man-hours were worked or managed across the Group s operations (2003: approximately 38 million). During the year, the Group experienced 112 recordable injuries (RIs) (2003: 124), representing an RI frequency rate of 0.57 per 200,000 man-hours (2003: 0.65) and 14 LTIs (2003: 9), representing an LTI frequency rate of 0.08 per 200,000 man-hours (2003: 0.05). The Directors believe these frequency rates demonstrate a good 54

55 level of performance when compared against annual OPG (International Association of Oil and Gas Producers) performance measures, being an LTI frequency rate of 0.32 per 200,000 man hours and an RI frequency rate of 0.97 per 200,000 man hours. Regrettably, sub-contractors working for the Group have experienced a total of three fatalities, one in each of FY 2003, FY 2004 and during FY Five H&S Executive improvement notices have been served on Petrofac Facilities Management during Of these, two relating to Heather and Thistle are very recent and have not been entered into on the H&S Executive public register of enforcement notices website as they are currently in the appeal window. Of the remaining three, two have been complied with and one (relating to a failure to implement a system to monitor safety critical elements of the installation) is outstanding although work is in progress in this regard. In addition, one H&S Executive prohibition notice has been served on Petrofac Facilities Management on 16 September 2005 relating to certain parts of the drilling infrastructure on the Kittiwake offshore installation which are operated by a third party drilling contractor. Work is in progress to ensure appropriate rectification. Petrofac is also party to a prosecution brought by the H&S Executive, further details of which are set out in paragraph 12 of Part IX Additional Information. Environmental incidents The Group monitors environmental incidents carefully. An incident which results in the accidental emission or discharge of a substance categorised as harmful to the environment is recordable according to the level of emission or discharge, with three levels of recording based on their consequence, Level 1 being the most serious. During the three years and 6 months ended 30 June 2005, the Group has recorded only two environmental incidents. One Level 2 incident was the result of the discharge of sewage into controlled waters in North Wales (for further details see paragraph 12.6 in Part IX Additional Information ) and the other was a Level 3 incident with relatively minor consequences. The Directors place confidence on the effectiveness of Petrofac s environmental incident reporting, while continuing to seek opportunities for improvement. UKCS duty holder obligations Petrofac s UKCS offshore facilities management business is subject to particularly detailed health and safety regulation, as Petrofac is the duty holder for 16 offshore installations and COMAH Report holder for one onshore installation, which it manages for its clients. The duty holder of an installation must demonstrate that the facility has been designed and constructed to afford the lowest practicable risk of injury to the employees. As well as providing a fundamentally safe installation, the duty holder must prepare a safety case, which demonstrates that it has considered all the possible hazards that may occur and their likelihood of occurrence; and has minimised risks by adopting safe operating and maintenance practices. Details of certain regulations applicable to Petrofac as duty holder are set out below. The offshore industry is a hazardous and consequently highly regulated industry. Following the Cullen report into the Piper Alpha disaster, a detailed framework of legislation relating to the operation of an offshore installation was introduced, including the Offshore Installations (Safety Case) Regulations 1992 (the Safety Case Regulations). This legislation applies to Petrofac in relation to those UKCS installations for which it is the duty holder. The duties and responsibilities of a duty holder start with duties under the Health and Safety at Work Act 1974 as amended (HASAWA), imposing duties on employers and other parties to both employees and third parties. These duties are non-delegable and breach is punishable under criminal law. HASAWA also applies offshore. Certain secondary legislation has also been implemented under the HASAWA to address particular issues in the offshore industry, including: the Safety Case Regulations; the Offshore Installations and Wells (Design and Construction) Regulations 1996; the Offshore Installations (Prevention of Fire and Explosion and Emergency Response) Regulations 1995; and the Offshore Installations and Pipeline Works (Management and Administration) Regulations

56 The Safety Case Regulations set out the requirement for the operator of fixed or mobile installations to prepare a safety case and for that safety case to be examined by the H&S Executive. The safety case identifies safety critical elements, for instance an item of a plant, failure of which could cause or contribute substantially to a major accident. Such plant must be identified, a performance standard set and the process and performance verified. The operator must conform with the safety case as accepted by the H&S Executive. The Safety Case Regulations further create a framework of non delegable duties, with the responsibility for fulfilment of those duties remaining with the duty holder owner or operator regardless of any contractual provisions relating to the actual operation of the unit. Breach of any such duties is punishable by criminal law. The specific duties, which are set out in the regulations referred to above relate to: the duties of installation managers, and related instructions and communication requirements; the integrity of offshore installations, safety of wells, safety of the workplace offshore and arrangements for the verification of safety critical elements; and preventative and protective measures to be taken to manage fire and explosion hazards and to secure emergency response. Similar legislation applies to onshore installations in the UK, for example to onshore gas terminals. The report holder under the Control of Major Accident Hazards Act 1999 (COMAH) has overall responsibility for the health and safety of the onshore installation. Contractual issues Many of the Group s contracts, particularly EPC contracts and Operations Services contracts set the standards and targets in relation to HSE, to which the Group is contractually required to adhere. Where in-country HSE legislation exists, this is typically defined in the contracts and often supplemented by client specific requirements. In some cases, the HSE requirements of both client and host country are below the Group s expectations. In these cases or in the absence of any specific HSE requirements in a contract, the Group s internal guidelines on HSE management strategies, policies and expectations provide the default requirements. Typically, and at an early stage, a contract will require a specific HSE plan to include specific reference as to how the contractual requirements will be met. The Group seeks to educate the personnel engaged on the relevant project to ensure that they are aware of the standards required and the importance of meeting such standards. The Group has generally been successful in achieving at least the HSE standards required of it pursuant to these plans. Security The Directors regard the security of Petrofac s personnel, property and reputation as a priority and accordingly the Group is developing a security management strategy to manage these risks. The strategy focuses on many aspects of the Group s operations but the security of Petrofac s personnel who have to travel and work in countries where the social and political conditions are often insecure is the main focus of the security programmes currently in place. The basis of Petrofac s strategy is the development and execution of security plans, developed by each division specifically for each location. Petrofac also receives support from a third party security services provider, which includes input into the Group s security plans, the provision of local risk assessments and also a full time monitoring service for all of the Group s geographical locations. 6. Risk management Petrofac manages risk through a set of delegated authorities which provide that any significant additional risk, whether arising from, inter alia, new contracts or investments, counterparty exposure or new process, technology or country of operation, has to be reviewed by the Risk Review Committee and approved at either the divisional board level or, where more significant, at main Board level. 56

57 The Risk Review Committee is chaired by the Group Chief Executive and its members are independent of the proposal under review. The committee is charged with examining a proposed activity and the steps being taken by the project sponsor to address the areas of risk to which it exposes the Group. The permanent members of the Risk Review Committee are the Group Chief Executive, the Chief Financial Officer and the Director of Group Legal and Commercial Affairs. Other senior employees are co-opted to the Risk Review Committee on an ad hoc basis. The Group requires each individual business unit to take responsibility for identifying the risks inherent in bidding for and accepting new business and in managing existing contracts. Each division operates a peer review process, whereby colleagues undertake an independent assessment of the conclusions reached by bid proposal teams. Each new business proposal is subject to the internal reviews identified above. Subsequently, certain types and size of proposal are subject to further review by the Risk Review Committee. This committee will make a recommendation to the divisional board or to the Board as appropriate as to whether a particular project or activity should be pursued having regard, inter alia, to the sustainability of the Group s business and its reputation. The nature of risk, and therefore the procedures required to identify and assess those risks, differ across the Group s three divisions. Engineering & Construction Most of the E&C Division s business is undertaken on a lump sum basis. In order to identify and manage the business and financial risks inherent in lump sum contracts, the E&C Division has adopted a procedure aimed at ensuring that contracts are bid for and accepted only on the basis of a thorough understanding of the specific risks and how these might be mitigated, whether through contractual negotiation, involvement of counterparties (including sub-contractors) and suppliers or through appropriate insurances. During consideration of a bid proposal, various risk factors will be evaluated, including technical risk and the availability of appropriate resources to ensure competent and timely execution of the project (including procurement of equipment, materials, and services and logistical issues relating to the site concerned); counterparty risk (including clients, partners, sub-contractors and suppliers); the contractual liability regime being proposed; the likelihood of achieving a satisfactory negotiated position and the cost of mitigating any remaining risks; the HSE requirements and the HSE standards of the counterparties involved; financial risk; and country and political risk. Detailed consideration of these factors allows a clear assessment to be made as to the viability of a project, the appropriateness of contracting on a sole basis or in partnership and the financial reward required to compensate for the risk to be undertaken. Upon taking a decision to pursue a project, the next step is to seek to mitigate satisfactorily any identified risks. This can be done by: negotiation of contract terms and conditions, including payment terms and variation approval procedures to minimise contract and financial risks; ensuring that all projects undertaken are within the Group s technical competence and that the relevant resources are available to commit to it; partnering with other companies where strategically important to do so but ensuring an appropriate balance between relative risk and reward; selecting appropriate project counterparties, be they partners, sub-contractors or vendors, based on technical strength and experience and financial strength; ensuring any exposure to potential contractual liabilities is reflected in the contractual arrangements agreed with vendors and sub-contractors; estimating and controlling costs accurately, drawing on the Group s significant experience in procuring equipment, materials and services; regular project reviews by senior management to ensure that any issues arising are properly considered and resolved; 57

58 obtaining the necessary insurance required to cover the services provided and reduce financial exposure; requiring clients, partners, and sub-contractors to obtain the necessary insurance and indemnity agreements, where possible; procuring materials and equipment effectively and efficiently and, to the extent possible, in the currency of the project contract, in order to reduce currency exposure; and using experienced and qualified project managers. Operations Services The OS Division typically contracts on a cost-reimbursable basis and, as a result, the commercial and financial risks are different from, and less significant than, those involved with lump sum contracts. However, HSE risks are common to both divisions. Within the OS Division, the more basic services, such as manpower supply, are provided on the simple basis of cost-reimbursement plus an agreed margin. As the technical level of service increases, the complexity of the remuneration arrangements tends to increase too. Typically, a schedule of rates will be agreed with the client and work undertaken will be reimbursed at the agreed rates (termed open rate ); alternatively, for some clients, contracts may be priced with an agreed cost recovery margin for a fixed period, but with the risk of cost inflation during that period on certain cost lines residing with the contractor. This approach is termed closed rate. The progression from cost plus, through open rate to closed rate, requires Petrofac to ensure margins are protected and not eroded through underestimation of cost inflation, typically driven by scarcity of resource. Where appropriate, incentive income will be negotiated so as to align Petrofac s revenue with the achievement of performance measures that reflect the client s priorities such as production uptime, operating expenditure and cashflow improvements. The Directors believe that the business and financial risks inherent in the OS Division, particularly within its operations in the UKCS, are lower than those in lump sum contracts in the E&C Division (for example, contractual financial penalties and liquidated damages are unusual); correspondingly, however, gross margins are typically lower. Nonetheless, the OS Division operates a similar assessment process to that of the E&C Division when considering potential new business. Outside the UKCS, specifically in the Middle East, North Africa and Papua New Guinea, contractual terms are similar but more commonly also include penalties for underperformance and bonuses for performance. For example, remuneration may be based on an agreed schedule of rates but be translated into a lump sum fee (with liquidated damages for non-performance) but with additional works being undertaken on a cost plus basis. Such contracts are subject to the same assessment of risk and reward as the rest of the OS Division s contracts. Resources In common with the E&C and OS Divisions, the Resources Division undertakes a risk assessment relating to new business. All investments must meet the two principal criteria of generating an internal rate of return satisfactory to the Group and offering the possibility for services to be provided by the wider Petrofac Group. The risks examined include an assessment of the counterparties involved in terms of reputation, competence, existing relationships with the Group and financial strength, country and political risk and exposure to changes that might have a bearing on cost, such as legislation. All investments of more than US$1 million are required to be reviewed by the Risk Review Committee and the assessment of all investments follows a form, and is based on assumptions, which is periodically reviewed and approved by the Board. Investments of more than US$10 million require approval by the Board. The base case oil price assumption for investments made by the Resources Division is currently US$25 per barrel (Brent) and 23 pence per therm gas. 58

59 7. Employee Share Schemes The Petrofac Limited Executive Share Scheme (the ESS) Introduction The ESS was established in 2002 and provides selected participants with the opportunity to acquire a participatory interest in Ordinary Shares, financed as to 75 per cent. of the acquisition price by way of a non-recourse loan from the Company. Participatory interests over a total of 57,055,960 Ordinary Shares remain outstanding under the ESS. Summary A participatory interest in Ordinary Shares means an absolute interest in Ordinary Shares subject to certain terms and conditions as set out in the ESS rules. Pursuant to such rules, the Ordinary Shares comprised in participatory interests acquired before Admission must be held in the name of the trustee of the Petrofac Limited Executive Share Trust (the Trustee) as security for obligations accepted by participants under the ESS rules, including but not limited to obligations under the loan agreement entered into by the participant and the agreement that the voting rights attaching to such Ordinary Shares shall be exercised only in accordance with the written instructions of the Directors. A participant is required to repay the loan used to acquire a participatory interest, together with any interest, in three equal annual instalments. The interest rate is calculated by reference to the rate charged by the Internal Revenue Service of the United States. A participant is entitled to any and all dividends and other distributions paid in respect of the Ordinary Shares comprised in a participatory interest. However, under the terms of the loan agreement, a participant agrees that the Trustee may first apply any dividends received on such shares in satisfaction of monies owing under the loan agreement. Effect of Admission On Admission, most participants will be entitled to exercise the voting rights attributable to the Ordinary Shares comprised in their participatory interest themselves subject to the Articles and to require the Trustee to transfer such Ordinary Shares to them provided that their loan has been repaid in full. On Admission, most participants may direct the Trustee to sell a proportion of the Ordinary Shares comprised in their participatory interests at the Offer Price. The rules of the ESS provide that the sale proceeds should first be applied in satisfaction of outstanding monies due under participants loan agreements. In the case of a small number of participatory interests acquired under the ESS, but not the Ordinary Shares held by the Trustee, the contractual voting and transfer restrictions do not fall away until the expiry of the relevant restricted period, being between one and three years from the date the participatory interest was acquired. The ESS will continue to be operated post-admission in relation to existing participatory interests although no further participatory interests will be awarded. The Petrofac Performance Share Plan (the PSP) Introduction The PSP was established by resolution of the Board on 13 September 2005, conditional upon Admission. Participants are granted contingent awards to receive Ordinary Shares which shall vest free of charge subject (in normal circumstances) to the continued employment of the participant and to the extent that performance conditions have been satisfied. The vesting of an award (under both the PSP and the DBSP which is summarised in the following section) means that the participant becomes entitled to receive the Ordinary Shares to which his award relates. 59

60 Eligibility Awards will be made to employees and executive directors selected by the Remuneration Committee of the Board (the Remuneration Committee) at its discretion. Individual Limit In any financial year of the Company, no participant may be granted awards over Ordinary Shares with a market value in excess of 100 per cent. of basic salary or, in circumstances which the Remuneration Committee deems to be exceptional, 150 per cent. of basic salary. Vesting of Awards It is currently intended that, provided the participant is still employed by the Group, awards will vest on the third anniversary of their date of grant to the extent that testing performance criteria, determined by the Remuneration Committee at the date of grant, have been satisfied. For initial awards, it is envisaged that vesting of a proportion of the awards will depend upon Petrofac s total shareholder return (TSR) performance as compared with the TSR performance of selected relevant companies and vesting of the balance of the awards will be contingent upon Petrofac s performance against earnings per share growth targets. Cessation of Employment If a participant dies, his award will vest in full and the relevant number of Ordinary Shares will be transferred to his personal representatives as soon as practicable. Such vesting will not be subject to the satisfaction of the performance conditions. If a participant s employment ceases before the end of the vesting period, he will not automatically forfeit his award provided he leaves by reason of injury, ill-health, disability, redundancy, retirement, as a result of the company by which he is employed being transferred outside the Group, or in other circumstances which, in the view of the Remuneration Committee, justify him being treated as a good leaver. In such cases, the maximum number of Ordinary Shares which a participant may receive will usually be determined on a pro-rated basis by reference to the time elapsed since the date of the award. However, vesting will not be accelerated as a result of leaving and such vesting will be subject to the satisfaction of the performance conditions at the end of the relevant performance period unless the Remuneration Committee, in its discretion, determines otherwise. Cessation of employment for any other reason will cause all unvested awards to be forfeited. Change of Control The vesting of awards on a change of control will usually be determined on a pro-rated basis. However, vesting will be subject to the discretion of the Remuneration Committee, having regard inter alia to the progress to date in meeting the performance conditions. The Petrofac Deferred Bonus Share Plan (the DBSP) Introduction The DBSP was established by resolution of the Board on 13 September 2005, conditional upon Admission. Under the DBSP, participants may volunteer or may be required to invest a proportion of their bonuses in Ordinary Shares. The Company will then grant matching awards over Ordinary Shares. Eligibility Employees and executive directors will be eligible to participate in the DBSP. Participation will be at the discretion of the Remuneration Committee. Awards Two types of award will be made under the DBSP. If the Plan is operated in any year and a bonus is payable, the Remuneration Committee may determine that part of a participant s annual bonus is delivered in Ordinary Shares or may invite selected employees to elect to receive part of their bonus in Ordinary Shares. These shares will be known as Invested Shares comprised in Invested Awards. 60

61 Following such investment, a further award will be granted over a number of Ordinary Shares bearing a specified ratio to the number of Invested Shares. These further awards are referred to below as Matching Awards. Vesting Awards will generally only vest three years after grant and provided that the participant does not leave the Company s employment during that three year period (although there are certain good leaver exceptions (see below). In addition, the vesting of Matching Awards may be subject to the satisfaction of performance conditions. Cessation of Employment If a participant dies, his awards will vest in full. If a participant is a good leaver his Invested Awards will vest in full and his Matching Awards will vest on a pro-rated basis. Vesting of Matching Awards which are subject to performance conditions will be subject to satisfaction of those conditions at the end of the relevant performance period unless the Remuneration Committee, in its discretion, determines otherwise. Cessation of employment for any other reason will cause all unvested awards to be forfeited. Change of Control In the event of a change of control, Invested Awards will vest in full but Matching Awards will usually vest on a pro-rated basis and taking into account the extent to which any performance conditions have been met. However, this is subject to the discretion of the Remuneration Committee. The Petrofac Approved Share Incentive Plan (the SIP) Introduction The SIP was established by resolution of the Board on 13 September 2005, conditional upon Admission and has been submitted to HM Revenue & Customs for informal approval under Schedule 2 to the Income Tax (Earnings and Pensions) Act The SIP is established under a trust deed with a UK resident trustee. Eligibility All employees and executive directors of the Group who are UK resident and have been employed for a specified qualifying period are eligible to participate in the SIP. The qualifying period may be up to 18 months. The SIP can be extended to non-uk resident employees at the discretion of the Directors. Free Shares Up to the statutory maximum (currently 3,000), Ordinary Shares may be awarded free of charge to each eligible employee in each tax year (Free Shares). The Directors may choose to make the award of Free Shares subject to the satisfaction of performance targets. The holding period during which the Free Shares must be held in trust may be anything between three and five years. Partnership Shares Each eligible employee may be invited to use up to 1,500 per tax year of pre-tax salary (or, if less, 10 per cent. of salary) to purchase Ordinary Shares ( Partnership Shares ). The SIP permits deductions from salary to be accumulated over a period of time set at the discretion of the Directors but not exceeding 12 months (the Accumulation Period ). Where there is an Accumulation Period, the price at which Partnership Shares are acquired on behalf of employees will be the lower of the market value of an Ordinary Share at the beginning of the Accumulation Period and on the acquisition date. Where there is no Accumulation Period, the price at which Partnership Shares are acquired will be the market value on the acquisition date. There is no holding period for Partnership shares. Matching Shares Partnership Shares purchased by eligible employees may attract, at the discretion of the Directors, an award of free Ordinary Shares (Matching Shares) in a ratio (to be determined by the Directors) of up to two Matching Shares for each Partnership Share. The holding period for Matching Shares must be between three and five years. 61

62 Dividend Shares The Directors may require or permit eligible employees to reinvest dividends received on Ordinary Shares held under the SIP in further Ordinary Shares (Dividend Shares) up to a limit of 1,500 per employee in any tax year. There is a three-year holding period for Dividend Shares. Cessation of Employment Free and Matching Shares If a participant dies or ceases to be an employee of the Group by reason of injury, ill-health, disability, redundancy, retirement on or after reaching the age of 60 or as a result of the company by which he is employed being transferred outside the Group, any Free Shares or Matching Shares held by the SIP trustee will be transferred to the participant (or his personal representatives). When Free Shares or Matching Shares are awarded, the Directors may determine that a participant who ceases employment with the Group for any reason other than as outlined in the above paragraph within three years of the allocation of the Free Shares or Matching Shares will forfeit them. Where forfeiture does not apply, the SIP trustee will transfer the Ordinary Shares to the participant. When Matching Shares are awarded, the Directors may stipulate that if the related Partnership Shares are withdrawn from trust within three years, the Matching Shares will be forfeited. Partnership and Dividend Shares Whenever and for whatever reason a participant ceases to be an employee of any Group company, his Partnership Shares and Dividend Shares will be transferred to him. Change of Control In the event of a change of control of the Company, any shares received as consideration will be held in trust under the SIP on the same terms as the Free Shares, Partnership Shares, Matching Shares or Dividend Shares in exchange for which they are received. Dividend and voting rights Participants will be the beneficial owners of the Ordinary Shares held by the trustee of the SIP for them. All dividends and other distributions received in respect of the Ordinary Shares which are not reinvested in Dividend Shares will be passed on to the participants concerned by the trustee as soon as practicable after receipt. The trustee will exercise the voting rights attaching to the Ordinary Shares in accordance with the wishes of the beneficial owners provided that participants have given prior voting directions in writing. Terms applying to the New Employee Share Plans generally Administration Each of the New Employee Share Plans will be administered by the Remuneration Committee, other than in the case of the SIP, which will be administered by the Directors. Overall Limits Not more than 10 per cent. of the Company s issued share capital may be allocated or issuable under the PSP, the DBSP and the SIP and any other discretionary employee share plan adopted or established by the Company in any ten-year period. Not more than five per cent. of the Company s issued share capital may be allocated or issuable under the PSP and the DBSP and any other employee share plan adopted or established by the Company in any ten-year period. For the purposes of the above limits, shares are allocated when an award to acquire unissued shares is granted or when shares are issued other than in respect of such an award, and awards which have lapsed or are over shares which are already in issue are to be disregarded. 62

63 Voting, Dividend and Other Rights Other than under the SIP, participants will have no voting or dividend rights in respect of Ordinary Shares until awards vest. However, when a dividend is paid, the number of Ordinary Shares comprised in awards under the PSP and the DBSP will be increased by the number of Ordinary Shares which could have been acquired with the amount of dividend which would have been received had the participant been the legal and beneficial owner of the Ordinary Shares comprised in the award. The vesting of the extra Ordinary Shares will be subject to the same vesting terms as the original Ordinary Shares. In the event of a variation of the Company s share capital, the number of Ordinary Shares comprised in an award may be varied in such manner as the Remuneration Committee considers appropriate. Ordinary Shares allotted under any of the New Employee Share Plans will rank pari passu with the existing Ordinary Shares with the exception of rights attaching by reference to a record date prior to the allotment date. Application will be made to the UK Listing Authority for all such Ordinary Shares to be listed. Awards are non-transferable and non-pensionable. Amendments Subject to what follows, the SIP may be amended in any respect by the Directors and the rules of the PSP and the DBSP may be amended in any respect by the Remuneration Committee. The prior approval of the Company in general meeting will be required for specified amendments to the material benefit of participants. No amendment may be made to the rules of a plan if it would adversely affect the rights of participants without the approval of the requisite majority of participants. Minor amendments to benefit the administration of the relevant plan, to take account of changes in legislation, to obtain or maintain favourable tax, exchange control, or regulatory treatment or to take account of a corporate transaction may, however, be made without the need for either of the approvals set out above where such amendments do not alter the basic principles of the relevant plan. No amendment to the SIP shall take effect without the prior approval of HM Revenue & Customs, where such approval is required. Overseas Employees When making awards to employees resident outside the United Kingdom, the Remuneration Committee may modify the terms of the relevant New Employee Share Plan, other than the SIP, to take account of tax laws or other legal or regulatory requirements in the relevant country. The above description summarises the principal features of the ESS, the PSP, the DBSP and the SIP but does not form part of their detailed rules (or trust deed, in the case of the SIP). The description should not, therefore, be taken as affecting the interpretation of the detailed terms and conditions of the ESS, the PSP, the DBSP and the SIP. A full copy of the rules of the ESS, the PSP and the DBSP and the rules and trust deed of the SIP are available for inspection as described at paragraph 21 of Part IX Additional Information. 8. Dividend policy The Directors intend to adopt a dividend policy which will reflect the long term earnings and cash flow potential of the Group, having taken into account the Group s capital requirements, whilst maintaining an appropriate level of dividend cover. 63

64 From 1 January 2006 the Directors intend to pay an interim and final dividend in respect of each financial year, with approximately one-third of the full year s dividend being payable as an interim dividend and two-thirds as a final dividend. The Group reports its financial results in US Dollars and will therefore declare dividends in US Dollars, together with a Sterling equivalent based on the exchange rate at the point the dividend is declared. Unless Shareholders elect to the contrary, they will receive the Sterling equivalent. Had Petrofac s Ordinary Shares been listed throughout the 2004 financial year, the Directors believe that they would have declared aggregate dividends equal to 25 per cent. of profit for the period from continuing operations (excluding the charge on variable rate unsecured loan notes which were converted into A ordinary shares on 21 June 2005). Going forward, the Group may revise its dividend policy from time to time. As a holding company, the ability of Petrofac to pay dividends will be dependent upon dividends and interest being distributed to it by its subsidiaries. With respect to the 2005 financial year, and, in the absence of unforeseen circumstances, the Directors intend to recommend a final dividend at the time of announcing the preliminary results for the 2005 financial year expected to be in March 2006, which it is expected will be payable in May Since the Group will only be public for approximately three months of 2005, the final dividend declared will be approximately half the level that would have been declared had Petrofac been listed for the whole of the 2005 financial year, having taken into account the Directors intention to pay two thirds of the full year dividend as a final dividend. For risks relating to dividends, please see Part II Risk factors. 64

65 PART IV Directors and Senior Managers 1. Board members Rodney Chase, aged 62, Non-Executive Chairman 3 Rodney Chase was appointed Non-Executive Chairman of Petrofac on 21 June Rodney spent 38 years at BP plc, of which 11 were served on its board. He was deputy group CEO on his retirement from the BP group in May He also spent time as CEO of the exploration and production, and marketing and refining divisions. He is currently non-executive deputy chairman of Tesco plc, non-executive director of Computer Sciences Corporation, non-executive director of Nalco Company and senior advisor to Lehman Brothers. He has previously held positions as a board member of BOC plc and Diageo plc. Michael Press, aged 58, Non-Executive Director, Senior Independent Director 123 Michael Press was appointed to the Petrofac Board in January 2002, having previously held senior executive positions for the Standard Oil Company Inc and BP and as a main board director of Amerada Hess. Between 1997 and 2001, Michael held various posts at KBC Advanced Technologies including non-executive director, executive chairman, and chief executive. He is currently also non-executive chairman of SPS International, a supplier of downhole tools and services used in wellbore clean-up and filtration, a director of ABARTA Inc. and T3 Energy Services and a member of the advisory board of Pharmadule Emtunga. Kjell Almskog, aged 64, Non-Executive 123 Kjell Almskog was appointed to the Petrofac Board in March After starting his professional career in brand management, with Procter & Gamble, Kjell subsequently spent some 25 years in various senior executive positions. During 13 years in the ABB group, Kjell was country manager in Norway while, in parallel, developing a substantial and highly successful international oil and gas activity, ultimately becoming group executive vice-president and head of ABB Oil, Gas and Petrochemicals. In 1998, he moved to Kvaerner as chief executive with responsibility for executing a major turnaround of that business until its acquisition by Aker in Presently, Kjell is senior advisor and non-executive director of several international companies, including Orkla, a large listed Norwegian group involved in branded consumer goods, chemicals and financial investments. He is also chairman of the Kverneland Group, a Norwegian listed international supplier of agricultural machinery. Bernard de Combret, aged 62, Non-Executive 123 Bernard de Combret was appointed to the Petrofac Board in November Bernard is an international consultant and former deputy chairman of TotalFinaElf s (TFE) executive committee. Following senior positions in both foreign affairs and the Ministry of Finance with the French Civil Service, he spent over 20 years with the Elf Group. During his industry career, Bernard was heavily involved in building the trading organisation of Elf Aquitaine and then subsequently Total. As chief executive of refining marketing, he played a leading role in increasing profitability of the downstream sector and, in 2000, became deputy chairman of TFE s executive committee, president and chief executive for gas and power and chief executive for trading and shipping. Bernard left TFE in 2002, after successful completion of the merger. He is currently a director of AXA-RE and Winstar Resources Ltd. Ayman Asfari, aged 47, Group Chief Executive 3 * Ayman Asfari joined Petrofac in 1991 to establish Petrofac International Ltd. Ayman has 25 years experience in the oil and gas industry and served as Chief Executive Officer of Petrofac International until his appointment as Group Chief Executive of Petrofac Limited in January Ayman previously worked as the managing director of a major civil and mechanical construction business based in Oman. 1 denotes a member of the Audit Committee 2 denotes a member of the Remuneration Committee 3 denotes a member of the Nominations Committee * denotes a permanent member of the Risk Review Committee 65

66 Keith Roberts, aged 48, Chief Financial Officer* Keith Roberts joined Petrofac in March 2002 as Chief Financial Officer having spent most of his working life as an investment banker based in the city of London. After positions in commercial banking with Standard Chartered Bank and then with County Bank, the merchant banking subsidiary of National Westminster Bank, Keith moved into corporate finance with Hawkpoint Partners where he was a managing director and a member of the operating committee. Keith is also a non-executive director of The Peacock Group, a UK listed value-for-money clothing retailer. Maroun Semaan, aged 49, Chief Executive, Petrofac Engineering & Construction Maroun Semaan joined Petrofac in 1991 to establish Petrofac International Ltd. From 1977 to 1991, Maroun held various project positions with Consolidated Contractors International Co. (CCC), based in the Middle East, where he was involved in the management of oil and gas pipeline, process facilities and civil works construction contracts in Oman and Bahrain. He was appointed Chief Executive of Petrofac Engineering & Construction in April Other divisional chief executives Amjad Bseisu, aged 42, Chief Executive, Petrofac Resources Amjad Bseisu joined Petrofac in 1998 and founded the Resources investment business. From 1984 to 1998, Amjad worked for the Atlantic Richfield Company (ARCO) starting his career as senior engineer in the drilling and production division and moving to the position of vice-president Arco Petroleum Ventures, with responsibility for operations and commercial activities in the Middle East and North Africa and ultimately, in 1996, as head of International Marketing, Negotiations and Business Development and president of ARCO Petroleum Ventures and ARCO Crude Trading, Inc. Robin Pinchbeck, aged 52, Chief Executive, Petrofac Operations Services Robin Pinchbeck joined Petrofac in 2002 to establish an independent facilities management business and has over 30 years experience in the upstream oil and gas industry. Following petroleum engineering and general management roles worldwide with BP, in 1995 he became managing director of Atlantic Power & Gas, a leading UK North Sea operations management services provider which was sold in 1998 to Petroleum Geo-Services and subsequently acquired by Petrofac in Robin was appointed Chief Executive of Operations Services in April Robin is a non-executive director of Sondex plc, a UK listed oilfield logging technology company. 3. Senior Managers Engineering & Construction Marwan Chedid, aged 44, Executive Vice President, Operations Marwan Chedid has 21 years experience in the oil and gas sector, and joined Petrofac in 1992 to help establish its international office in Sharjah, UAE. Prior to joining Petrofac, Marwan worked in various project positions at Consolidated Contractors Company. Marwan is a member of the E&C divisional board. Rob Jewkes, aged 49, Executive Vice President and Managing Director, Petrofac Engineering Rob Jewkes joined Petrofac in January 2004, with the primary objective of building a Europe-based engineering and construction division, to complement the Sharjah-based operations. Rob has over 25 years experience in the oil and gas engineering and construction industry, principally gained with the Australian Clough Group, where he established Clough s offshore engineering and construction division, and held a number of positions both in Australia and South-East Asia, ultimately serving as chief executive officer of the main operating company, Clough Engineering. Rob has many years of project management experience in facilities projects both in the Australasia region and in Europe and the Middle East. Rob is a member of the E&C divisional board. Vivek Prakash, aged 48, Vice President, Finance and Administration Vivek Prakash joined Petrofac in 2004 with responsibility for finance, HR, for administration and IT. Vivek has over 25 years of experience of which 15 years were in the oil and gas contracting sector as director of the Dodsal Group, overseeing the activities of the Group in the MESA region. Vivek is a chartered accountant by qualification and is a member of the E&C divisional board. 66

67 Rajesh Verma, aged 55, Executive Vice President, Technical Services Rajesh Verma has 30 years experience in the oil and gas sector and joined Petrofac in 1992 to help establish its international office in Sharjah, UAE. Prior to joining Petrofac, Rajesh worked in various project management positions at Consolidated Contractor Company (CCC) in the Middle East as well as with Tata Consulting Engineers in Mumbai, India. Rajesh is a member of the E&C divisional board. Peter Warner, aged 48, Senior Vice President, Sales and Marketing Peter Warner joined Petrofac in 2000 to lead the sales and marketing function of the E&C Division. He has over 25 years experience in the international E&C contracting business. He joined Davy Powergas in the late 1970s as a process engineer and subsequently held project and executive level financial, strategic planning and sales positions in the UK and the USA. During the 1990s, Peter held leading sales and marketing positions with Davy McKee, M W Kellogg and Stone & Webster. Peter is a fellow of the Institution of Chemical Engineers and a chartered engineer in the UK and was previously a licensed professional engineer in the USA. Peter is a member of the E&C divisional board. Operations Services Jim Atack, aged 54, Managing Director, Petrofac Facilities Management Jim Atack joined Petrofac in 2002 following the acquisition of PGS PS, formerly Atlantic Power & Gas. Jim joined Atlantic Power & Gas as operations and change manager for the takeover by Oryx of the Hutton, Murchison and Lyell oilfields in 1994, and was then the architect of similar work in Chevron s takeover of the Ninian Field in More recently he was engaged in the re-habilitation of the Ramform Banff FPSO, and establishing Petrofac as a full service facilities management company. Jim s prior experience spans some 17 years of oil and gas field production and development projects with BP in the North Sea, onshore UK, and Alaska. Jim is a member of the OS divisional board. Steve Bullock, aged 49, International Operations Director, Petrofac Facilities Management Steve Bullock joined Petrofac in 1994 and has 25 years experience in the oil and gas industry, including 12 years at Marathon Oil where he occupied a number of posts in Aberdeen, London and offshore, variously operating in commissioning, maintenance and production management roles. Steve is a member of the OS divisional board. Kevin Martin, aged 43, Financial Controller, Operations Services Kevin Martin joined Petrofac in 2002 following the acquisition of PGS PS, assuming the role of Finance Director of the facilities management business in 2003, and Finance Controller of the OS Division in Before the acquisition, he held senior finance posts within the PGS Atlantic Power group of companies from 1991 and within labour-supply contracting companies from Sandy Reid, aged 44, Sales and Marketing Director, Petrofac Facilities Management Sandy Reid joined Petrofac in 2002 to spearhead the early development of the international operations business prior to the acquisition of PGS PS, formerly Atlantic Power & Gas Limited. Sandy has over 20 years experience in various companies, including management posts at Atlantic Power & Gas Limited and BG Group. Sandy is a member of the OS divisional board. Murray Strachan, aged 41, Managing Director, Petrofac Training Murray Strachan joined Petrofac in 2004 following the acquisition of RGIT Montrose. Following a short period post qualification in commercial management within the UK construction industry until 1987, Murray has been in various commercial, operational, change management and senior general management roles within the service sector of the oil and gas industry, including within divisions of Maersk and Liberty Mutual. Murray joined RGIT Montrose in 2000, became group managing director in 2001 and led the management buyout of the business in early Murray is a non-executive director of CLAN, a north east Scotland cancer charity. Murray is a member of the OS divisional board. 67

68 Resources Rory Edwards, aged 49, Vice President, Business Development, Petrofac Resources Rory Edwards has had a 26 year oil industry career and has been with Petrofac for two years. He has worked in technical and commercial areas, asset management and general management all with independent or major companies including ENI Agip, Amoco, Shell, BG and Amerada Hess. He spent 13 years with Amerada Hess in the UK, latterly as deputy managing director of its international business and was responsible for operations in 8 countries. Rory trained as a petroleum engineer on graduating from university. Richard Hall, aged 45, Vice President, Project Development and Operations, Petrofac Resources Richard Hall joined Petrofac in 2003 and has 24 years oil industry experience. His first 10 years were spent in operating companies, including Amoco, Murphy Oil and Amerada Hess, developing a broad experience base in petroleum engineering, offshore operations supervision (production and well and rig related), field developments and commercial and head office functions. He then went on to be co-founder, co-owner and executive director of UWG Group, providing equipment and engineering solutions to operators worldwide. Richard trained as a petroleum engineer. Felix Lobo ACA, aged 39, Chief Accountant, Petrofac Resources Felix Lobo joined Petrofac in A chartered accountant with over 17 years of experience, he started his career in 1990 as an accounts officer with Hindustan Petroleum Corporation Limited, and was responsible for accounts at the marketing department of Gujarat Refinery. From 1990 to 1994, he worked at various locations within Hindustan Petroleum including head office. From 1995 to 1997, he worked as the accounts manager for Agroline Ventures Ltd. Lagos, Nigeria a commodities trading firm, and was responsible for the accounts and finance of the Group s clients in West Africa. Group Leigh Howarth ACA, aged 41, Group Financial Controller Leigh Howarth joined Petrofac in After starting his professional career with KPMG, Leigh moved into industry in 1992, initially working for WMS Group, an importer and distributor of window and door hardware. In 1996, Leigh joined Atlantic Power & Gas, a leading UK oil and gas service provider and, in 1998, was appointed group finance director to the business. In 2003, following the acquisition of this business by Petrofac in December 2002, Leigh relocated to the United Arab Emirates to head Petrofac s group finance function. Leigh is an associate chartered accountant and is a member of the OS divisional board. Richard Milne, aged 50, Director, Group Legal and Commercial Affairs* Richard Milne joined Petrofac as Director, Group Legal and Commercial Affairs in He qualified as a solicitor in 1980 and spent 8 years in various legal and financial positions within the Sedgwick Group, an international insurance broker. In 1990, he joined a corporate finance adviser J O Hambro Magan & Co. where he became a managing director and, following the acquisition of the business by National Westminster Bank in 1996, he became chief operating officer of the corporate finance business which became Hawkpoint Partners. He left Hawkpoint Partners in 1999 to become chief operating officer of Eastgate Group, an insurance outsourcing business. Following the sale of this business in 2000, he helped establish the London offices of corporate finance advisers Gleacher & Co and Tricorn Partners before joining Petrofac. Derek Moorfield, aged 57, Corporate Safety Director Derek Moorfield joined Petrofac in 2001 having spent most of his working life in the execution of risk and safety engineering of oil and gas EPC projects for various major operating companies. In 1978, following a career as an aeronautical engineer he moved into the oil and gas industry with NPCC, Abu Dhabi, as their first safety engineer later moving to Norway for Norsk Hydro. In 1989, he joined Granherne where, on behalf of Occidental Inc., he was the resident safety engineer, providing guidance on the implementation of the recommendations from Lord Cullen s Piper Alpha enquiry. Derek became corporate head of HSE for Granherne and also undertook * denotes a permanent member of the Risk Review Committee 68

69 resident HSE manager roles in major offshore EPC projects in Australia, South Africa and Brazil. Derek is a corporate member of the Chartered Institute of Management and the International Institute of Risk and Safety Management attained by the award of the Diploma in Industrial Management (CIMgmt) and the Diploma in Safety Management (BSC) required for the respective institutions. The business address of all the Directors and Senior Managers (including the divisional chief executives) named above is the registered office of the Company. 4. Corporate governance The Board places great emphasis on sound corporate governance and intends to comply with the principles of good governance and Code of Best Practice (the Combined Code). The Combined Code recommends that the board of directors of a UK public company should include a balance of executive and non-executive directors (and in particular non-executive directors), such that no individual or small group of individuals can dominate the board s decision-taking. The Combined Code further recommends that at least half of the Board, excluding the Chairman, should comprise non-executive directors determined by the Board to be independent, and that one non-executive director should be nominated as the senior independent director. Petrofac currently has seven Directors, three of whom are non-executive Directors considered by the Board to be independent. Michael Press has been nominated Petrofac s Senior Independent Director. As a result, the Directors consider that there is a satisfactory balance of decision making power on the Board. The Board has established an Audit Committee, a Remuneration Committee and a Nominations Committee with the following roles within the Group: Audit Committee The members of the audit committee are Bernard de Combret (Chairman), Kjell Almskog and Michael Press. Others may be co-opted onto the committee by the committee members. Meetings are held not less than three times a year. The Chief Financial Officer is invited to attend meetings where appropriate and the Company s auditors are regularly invited to attend meetings, including once at the planning stage before the audit and once after the audit at the reporting stage. Other Board members may also be invited to attend, although at least once a year the audit committee must meet the Company s external auditors without management being present. The role of the audit committee includes consideration of matters relating to the appointment of the Company s auditors and the independence of the Company s auditors, reviewing the integrity of the Company s annual and interim reports, preliminary results announcements and any other formal announcement relating to its financial performance. The Committee also reviews the effectiveness of the Group s system of internal control and compliance procedures. Remuneration Committee The members of the Remuneration Committee are Michael Press (Chairman), Kjell Almskog and Bernard de Combret. The primary duty of the Remuneration Committee is to determine and agree with the Board the framework or broad policy for the remuneration of the Company s Chief Executive, Chairman, the executive directors, the Company Secretary and such other members of the executive management as it is designated to consider. The remuneration of non-executive Directors is a matter for the Chairman and the executive members of the Board. No Director or manager may be involved in any decisions as to their own remuneration. Nominations Committee The members of the Nominations Committee are Rodney Chase (Chairman), Kjell Almskog, Ayman Asfari, Bernard de Combret and Michael Press. The Nominations Committee s terms of reference are to review regularly the structure, size and composition (including the skills, knowledge and experience) required of the Board compared to its current position and make its recommendations to the Board with regard to any changes. The 69

70 nominations committee also considers future considerations of the composition of the Board, taking into account the challenges and opportunities facing the Company, and what skills and expertise are needed on the Board. The nominations committee also makes recommendations to the Board about the membership of the audit and remuneration committees. The Directors believe that Petrofac will be in compliance with the requirements of the Combined Code to the extent these will be applicable on Admission. 5. Directors and Senior Managers interests in Ordinary Shares 5.1 The table below shows the interests of the Directors in the Ordinary Shares which would be notifiable to the Company in accordance with the New Articles (as summarised in paragraph 4(b)(iii)(F) of Part IX Additional Information ) and the interests of the Senior Managers in the Ordinary Shares which would be notifiable to the Company if the Senior Managers were Directors, in both cases as at 19 September 2005, being the latest practicable date prior to the publication of this document and as expected immediately following the Offer: Name No. of Ordinary Shares held as at 19 September 2005 (1) 70 Percentage of share capital as at 19 September 2005 (1) Expected No. of Ordinary Shares held immediately following the Offer (1) Expected Percentage of share capital immediately following the Offer (1) Directors Rodney Chase 800,000 (2) 0.2 1,000,000 (10) 0.3 Michael Press 400,000 (2) , Kjell Almskog 200,000 (2) ,000 (11) 0.1 Bernard de Combret 400,000 (2) ,000 (12) 0.2 Ayman Asfari 101,641, ,231, Keith Roberts 5,200,000 (2)(3) 1.5 3,380, Maroun Semaan 49,981, ,485, Senior Managers Divisional Chief Executives Amjad Bseisu nil n/a nil n/a Robin Pinchbeck 3,200,000 (2)(4) 0.9 2,080, Other Senior Managers Jim Atack 1,640,000 (2)(5) ,000 (13) 0.3 Steve Bullock 600,000 (2) ,000 (13) 0.1 Marwan Chedid 3,320,560 (6) 1.0 1,992,336 (13) 0.6 Rory Edwards 1,200,000 (2) ,000 (13) 0.2 Richard Hall 1,200,000 (2) ,000 (13) 0.2 Leigh Howarth 860,000 (2)(7) ,000 (13) 0.1 Rob Jewkes 1,660,000 (2)(8) ,000 (13) 0.3 Felix Lobo 127,600 (2) ,560 (13) 0.0 Kevin Martin 340,000 (2) ,000 (13) 0.1 Richard Milne Derek Moorfield 1,200,000 (2) 300,000 (2) ,000 (13) 180,000 (13) Vivek Prakash 400,000 (2) ,000 (13) 0.1 Sandy Reid 1,200,000 (2) ,000 (13) 0.2 Murray Strachan 1,800, ,080,000 (13) 0.3 Rajesh Verma 3,560,560 (2) 1.0 2,136,336 (13) 0.6 Peter Warner 1,065,120 (2)(9) ,072 (13) 0.2 (1) Assuming (a) no exercise of the Over-allotment Option; (b) the re-organisation of the Company s Share Capital (which is conditional upon Admission) having been completed; (c) the allotment and issue of all Ordinary Shares due to be allotted and issued under Petrofac s Long Term Incentive Plan (LTIP), which allotment and issue is conditional upon Admission; (d) each Director and Senior Manager selling his full entitlement of Ordinary Shares, including participatory interests in Ordinary Shares under the ESS and the LTIP, permitted for sale. (2) Shareholding of Ordinary Shares held (in whole or in part) through the ESS. (3) Includes 200,000 Ordinary Shares issued or to be issued to satisfy the vesting of awards under the LTIP.

71 (4) Includes 200,000 Ordinary Shares issued or to be issued to satisfy the vesting of awards under the LTIP. (5) Includes 40,000 Ordinary Shares issued or to be issued to satisfy the vesting of awards under the LTIP. (6) Includes 160,000 Ordinary Shares issued or to be issued to satisfy the vesting of awards under the LTIP. (7) Includes 60,000 Ordinary Shares issued or to be issued to satisfy the vesting of awards under the LTIP. (8) Includes 60,000 Ordinary Shares issued or to be issued to satisfy the vesting of awards under the LTIP. (9) Includes 120,000 Ordinary Shares issued or to be issued to satisfy the vesting of awards under the LTIP. (10) It is expected that Rodney Chase will purchase 200,000 Ordinary Shares in the Offer. (11) It is expected that Kjell Almskog will purchase 200,000 Ordinary Shares in the Offer. (12) It is expected that Bernard de Combret will purchase 200,000 Ordinary Shares in the Offer. (13) This assumes the sale of the maximum number of Ordinary Shares eligible for sale by such person, and is subject to confirmation. 5.2 The individual Directors purchasing Ordinary Shares in the Offer will have their applications satisfied in full. 5.3 As at 30 June 2005, US$1.42 million was outstanding under loans made by the Company to directors of the Company as at that date, for the purchase of participating interests in ordinary shares through the ESS. See Note 30 to the financial information set out in Part X Financial Information on Petrofac. The individual loans (including accrued interest payable) were US$1,334,242 to Keith Roberts and US$85,761 to Robin Pinchbeck. It is expected that these outstanding loans will be fully repaid by such individuals after the Offer, in whole or in part out of the proceeds of the Offer received by them. 71

72 PART V Selected financial information on Petrofac The table below sets out Petrofac s summary financial information for the periods indicated. The data has been extracted without material adjustment from and should be read in conjunction with, the Financial Information in Part X Financial Information on Petrofac which has been prepared in accordance with IFRS. As this is only a summary, investors are advised to read the whole of this document and not rely on the information summarised in this Part V. Consolidated income statement 6 months ended 30 June 2005 Unaudited 6 months ended 30 June Year ended 2004 Year ended 2003 Year ended 2002 Continuing operations Revenue 692, , , , ,398 Cost of sales (618,197) (345,099) (829,081) (554,198) (335,907) Gross profit 74,213 57, ,449 74,504 55,491 Selling, general and administration expenses (34,073) (29,008) (58,825) (38,705) (23,030) Other income 2,819 4,668 6,246 2,025 3,762 Other expenses (1,878) (1,076) (1,587) (77) (927) Profit from continuing operations before tax and finance costs 41,081 32,453 68,283 37,747 35,296 Finance costs (4,786) (3,685) (7,544) (1,046) (725) Finance income 1,389 1,209 1,997 1,073 1,645 Profit before tax 37,684 29,977 62,736 37,774 36,216 Income tax (expense)/income (1,292) (8,029) (16,699) (2,579) (2,194) Profit for the period from continuing operations 36,392 21,948 46,037 35,195 34,022 Discontinued operations Loss for the period from discontinued operation (202) (12,942) (13,162) (16,241) (12,268) Profit for the period 36,190 9,006 32,875 18,954 21,754 Attributable to: Petrofac Limited shareholders 36,190 9,052 32,921 22,118 22,068 Minority interests (46) (46) (3,164) (314) 36,190 9,006 32,875 18,954 21,754 Earnings per share (US$): From continuing and discontinued operations: Basic Diluted From continuing operations: Basic Diluted

73 Consolidated balance sheet 30 June ASSETS Non-current assets Property, plant and equipment 123, , ,395 93,268 Goodwill 49,631 49,653 29,594 31,854 Intangible assets 372 6,721 Available-for-sale financial assets 2,273 4,104 2,135 Other non-current assets 4,533 11,205 18,079 38,336 Deferred income tax assets 6, ,617 Investment in associate 1, , , , ,075 Current assets Inventories 1,635 1,702 1,589 2,671 Work in progress 153, , ,841 47,116 Trade and other receivables 209, ,042 96,485 88,238 Due from related parties 31,490 20,889 21,635 2,039 Other current assets 22,549 54,597 33,087 37,142 Cash and short-term deposits 141, ,534 97, , , , , ,730 Non-current assets classified as held for sale 1,914 3,678 3,771 7,838 TOTAL ASSETS 749, , , ,643 EQUITY AND LIABILITIES Equity attributable to Petrofac Limited shareholders Share capital 7,184 7,166 9,066 10,000 Share premium 29,219 28,553 52,592 59,018 Capital redemption reserve 10,881 10,881 8, Treasury shares (106) (1,018) Net unrealised gains on available-for-sale financial assets 1,301 2,395 1,127 Net unrealised gains/(losses) on derivatives (6,008) 22,964 (1,020) 1,132 Foreign currency translation (809) 1,688 1, Retained earnings 92,115 64,911 35,552 21, , , ,153 91,781 Minority interest 2,241 4,321 Total equity 133, , ,394 96,102 Non-current liabilities Interest-bearing loans and borrowings 85, ,787 85,627 83,221 Other non-current liabilities 13,315 12,789 4,525 4,952 Deferred income tax liabilities 2,922 1, , ,111 90,272 88,360 Current liabilities Trade and other payables 100, , , ,021 Due to related parties 1,526 1, Interest-bearing loans and borrowings 69,308 50,691 31,966 3,895 Income tax payable 3,938 3, ,597 Billings in excess of cost and estimated earnings 15,922 72,155 11,382 32,858 Accrued contract expenses and provisions 270, , ,519 97,548 Accrued expenses and other liabilities 52,082 44,336 22,318 22,821 Redeemable preference shares 7, , , , ,181 TOTAL LIABILITIES 615, , , ,541 TOTAL EQUITY AND LIABILITIES 749, , , ,643 73

74 Consolidated cash flow statement 6 months ended 30 June 2005 Unaudited 6 months ended 30 June 2004 Year ended 2004 Year ended 2003 Year ended 2002 Operating activities Net profit before income taxes and minority interests: Continuing operations 37,684 29,977 62,736 37,774 36,216 Discontinued operation (202) (12,942) (13,162) (11,326) (18,428) 37,482 17,035 49,574 26,448 17,788 Adjustments for: Depreciation, amortisation and impairment 13,265 12,696 27,888 11,059 4,329 Finance costs, net 3,350 2,460 5, (949) Minority interests , Other non cash items, net 2, (412) (158) 958 Gain on disposal of discontinued operation (12,507) Gain on disposal of investments (1,819) (2,402) (2,932) Operating profit before working capital changes 54,676 29,921 79,676 28,501 22,440 Trade and other receivables (7,574) (26,635) (99,582) (8,247) (10,017) Work in progress (44,572) 11,308 (6,196) (55,725) (17,616) Due from related parties (10,601) (19,596) 2,840 Inventories 67 (249) (113) 1, Other current assets 13,765 (9,560) 171 4,002 (20,353) Trade and other payables (15,274) (16,375) (4,581) (5,610) 51,322 Billings in excess of cost and estimated earnings (56,233) 12,166 60,773 (21,476) (14,407) Accrued contract expenses and provisions 91,311 (11,509) 28,489 52,971 4,579 Due to related parties 73 (108) 1, (352) Accrued expenses and other liabilities 2,835 8,472 17,965 (2,791) 3,645 28,473 (2,275) 78,693 (26,781) 22,143 Other non-current items, net (622) 11,901 19,123 13,689 (11,782) Cash generated from/ (used in) operations 27,851 9,626 97,816 (13,092) 10,361 Interest paid (5,296) (3,168) (5,695) (1,705) (1,169) Income taxes paid, net (7,548) (6,016) (13,278) (2,590) (777) Net cash flows from/ (used in) operating activities 15, ,843 (17,387) 8,415 Of which discontinued operations (112) (9,589) (8,903) (35,927) (451) 74

75 Consolidated cash flow statement (continued) 6 months ended 30 June 2005 Unaudited 6 months ended 30 June 2004 Year ended 2004 Year ended 2003 Year ended 2002 Investing activities Purchase of property, plant and equipment (6,257) (9,132) (17,142) (34,321) (52,324) Acquisition of business assets (695) (373) Acquisition of subsidiary, net of cash acquired (4,073) (9,119) (9,119) (16,111) Acquisition of interest in joint venture (1,000) (1,000) Purchase of intangible oil and gas assets (372) (3,744) (4,480) Purchase of available-for-sale financial assets (691) Net cash from disposal of discontinued operation 20,692 Proceeds from disposal of property, plant and equipment 1, , Proceeds from disposal of availablefor-sale financial assets 3,247 2,344 1,969 Movement in translation reserve (2,497) 1, Interest received 2,061 1,196 1, ,224 Investment in associate (1,000) Net cash flows used in investing activities (6,627) (19,855) (27,243) (11,082) (65,127) Of which discontinued operations 1, ,929 (6,662) Financing activities Proceeds from issue of share capital 1,511 1,511 Proceeds from interest-bearing loans and borrowings 20,347 45,722 31,412 88,455 Repayment of interest-bearing loans and borrowings (31,176) (14,712) (35,684) (2,294) (15,500) Purchase of derivative financial instruments (62) (1,000) Redemption of preference shares (7,336) (310) Shareholders loan note transactions, net 2,983 1,714 (1,581) 208 1,428 Transactions with employee share plan, net 655 (18) 3, (118) Exercise of option to acquire group shares (2,400) Repurchase of shares (30,760) (8,250) Equity dividends paid (6,586) (1,315) (1,315) Net cash used in reorganisation (16,288) Net cash flows (used in)/ from financing activities (16,177) (12,820) (19,153) 14,630 56,667 Of which discontinued operations 5,317 Net (decrease)/increase in cash and cash equivalents (7,797) (32,233) 32,447 (13,839) (45) Cash and cash equivalents at 1 January 127,823 95,376 95, , ,260 Cash and cash equivalents at period end 120,026 63, ,823 95, ,215 75

76 PART VI Operating and financial review The following review should be read in conjunction with the Financial Information set out in Part X Financial Information on Petrofac and the other financial information contained elsewhere in this document. This review contains forward-looking statements that involve risks and uncertainties. Petrofac s actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors including, but not limited to, those discussed in Part II Risk factors and in Forward-Looking Statements on pages 5 and 6 of this document. The financial information contained in Part X Financial Information on Petrofac has been prepared in accordance with IFRS and in compliance with the applicable requirements of Jersey law. References in this document to the Group s financial results are the financial results from continuing operations, unless otherwise stated. Percentage figures of divisional results relative to Group are, unless otherwise stated, calculated using, as the denominator, Group results after consolidation and elimination adjustments. EBITDA References to EBITDA in this document are to the profit before tax and net finance costs and before depreciation, goodwill and other amortisation and impairment losses. References to EBITDA margin are to EBITDA as a percentage of revenues. The Directors use EBITDA internally as an important supplemental measure of Petrofac s operational performance and believe it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in the oil and gas industry. EBITDA has its own limitations as an analytical tool and it should not be considered in isolation from, or as a substitute for, analysis of Petrofac s results of operations, as reported under IFRS. Some of the limitations of EBITDA as a measure are as follows: it does not reflect finance charges, or the cash requirements necessary to service interest or principal repayments, on Petrofac s debt; it does not reflect finance income arising from Petrofac s cash balances; it does not reflect taxes; although depreciation, goodwill and other amortisation are non-cash charges, the tangible or intangible assets being depreciated, amortised or impaired will often have to be replaced in the future; other companies in the oil and gas industry may calculate this measure differently, limiting its usefulness as a comparative measure. 1. Overview Petrofac is a leading international provider of facilities solutions to the oil and gas production and processing industry, with a diverse client portfolio which includes many of the world s leading integrated, independent and national oil and gas companies. Through its three operating divisions, Engineering & Construction (E&C), Operations Services (OS) and Resources, Petrofac designs and builds oil and gas facilities, operates, maintains or manages facilities and trains personnel, and, where return criteria are met and revenue synergies identified, co-invests with clients and partners. Petrofac s range of services allows it to meet its clients needs across the life cycle of oil and gas assets. Business segments The following tables show revenues, operating profit, net profit and EBITDA from continuing operations generated by Petrofac s three divisions in the 6 month period ended 30 June 2005 and the financial year ended 2004, as well as certain margin data. 76

77 6 months ended 30 June 2005 Engineering & Construction Operations Services Resources Consolidation and elimination US$ in thousands (unless stated otherwise) Total Revenue 398, ,668 22,572 (8,817) 692,410 Operating profit 22,867 12,391 8,769 (2,946) 41,081 Net profit 22,958 7,294 12,034 (5,894) 36,392 EBITDA 28,055 13,296 15,730 (2,735) 54,346 Operating margin 5.7% 4.4% 38.8% 5.9% Net margin 5.8% 2.6% 53.3% 5.3% EBITDA margin 7.0% 4.8% 69.7% 7.8% Total Discontinued operations, which are described in further detail at paragraph 11 below incurred a net loss of US$0.2 million during the 6 months ended 30 June Financial year ended 2004 Engineering & Construction Operations Services Resources Consolidation and elimination US$ in thousands (unless stated otherwise) Total Revenue 473, ,127 45,042 (7,105) 951,530 Operating profit 33,524 17,347 17, ,283 Net profit 33,100 9,643 6,953 (3,613) 46,083 EBITDA 41,880 21,135 32, ,065 Operating margin 7.1% 3.9% 38.1% 7.2% Net margin 7.0% 2.2% 15.4% 4.8% EBITDA margin 8.8% 4.8% 71.7% 10.1% Total Discontinued operations, which are described in further detail in paragraph 11 below, incurred a net loss of US$13.2 million during the 2004 financial year. Geographical segments The following tables show revenues, assets and capital expenditure by geographical segments for the 6 month period ended 30 June 2005 and the financial year ended Six months ended 30 June 2005 Middle East & Africa Former Soviet Union/Asia 77 Europe Americas Consolidated US$ in thousands Total Revenue 170, , ,206 1, ,525 Continuing operations 170, , ,206 1, ,410 Discontinued operations Carrying amount of segment assets 343, , ,376 7, ,012 Capital expenditure Tangible fixed assets 1,968 2,340 1, ,257 Intangible fixed assets 1, ,118

78 Financial year ended 2004 Middle East & Africa Former Soviet Union/Asia Europe Americas Consolidated US$ in thousands Total Revenue 281, , ,085 18, ,154 Continuing operations 281, , ,085 5, ,530 Discontinued operations 12,624 12,624 Carrying amount of segment assets 382, , ,576 12, ,357 Capital expenditure Tangible fixed assets 5,674 8,851 2, ,142 Intangible fixed assets 6,721 6,721 Backlog The following table sets out the backlog of the E&C and OS Divisions as at 30 June 2005 and 2004, 2003 and The definition of backlog is set out in paragraph 6 below. H US$ in millions Engineering & Construction 1, Operations Services 1,453 1, Total 2,494 1,740 1, As at 30 June 2005, the top five contracts (by backlog) accounted for, in aggregate, 68 per cent. of total backlog. 2. Background Corporate reorganisation Prior to January 2002, the Group s operations were owned or operated through a combination of companies organised in the United States and other countries in which a group of common shareholders owned various share interests. The principal holding company was Petrofac Corporation Limited (PCL). On 13 January 2002, the Group completed a corporate reorganisation through which the Company acquired full ownership of PCL and of the minority interests in PCL s subsidiaries that PCL did not already directly or indirectly own. The reorganisation resulted in PCL becoming a wholly owned subsidiary of Petrofac Limited and PCL wholly owning each of its direct subsidiaries. Subsequently, PCL was merged into Petrofac Limited. These reorganisation transactions included the issue of ordinary and preference shares and the payment of cash. Financial information for the 2002 financial year contains a full year s contribution from Petrofac s predecessor companies. Investment by 3i In May 2002, Petrofac raised long term capital from 3i through the issuance of US$40.25 million variable rate unsecured loan notes maturing in 2009 together with an option to purchase Petrofac ordinary shares representing 13.0 per cent. of the fully diluted ordinary share capital of Petrofac. This was subsequently increased to 16.2 per cent. reflecting the buyout and cancellation of approximately 25 per cent. of the Company s then issued ordinary share capital in October In June 2005, the conditions allowing the Company to call upon 3i to subscribe for its 16.2 per cent. interest were satisfied and the aggregate subscription amount was satisfied by the cancellation of the loan notes and the issue of A ordinary shares to 3i. Acquisitions Prior to 2002, Petrofac had not made any acquisitions. Recognising the opportunity to expand its business model and leverage its core business skills into new markets, the Group has since completed a number of acquisitions, the most significant of which was the acquisition of PGS PS 78

79 which established the core of the Operations Services Division. The Operations Services Division has broadened its service offering through further acquisitions, including RGIT Montrose Holdings Limited (RGIT), which now forms the core of the Group s Training business, and Rubicon Response Limited (Rubicon Response), providing emergency response management consultancy and training services. Further details of these acquisitions are set out below. From 1 January 2005, goodwill related to purchase acquisitions is no longer subject to amortisation. PGS Production Services On 11 December 2002, the Group acquired 100 per cent. of the issued and outstanding shares of PGS Production Group Limited, trading as PGS Production Services (PGS PS) together with its subsidiaries and joint ventures for a cash consideration of US$28.1 million, inclusive of acquisition costs and deferred and contingent consideration. The fair value of the identifiable assets and liabilities of PGS PS acquired was US$3.3 million including interest-bearing loan notes amounting to US$5.2 million and cash and short-term deposits amounting to US$8.3 million. PGS PS was renamed Petrofac Facilities Management Group Limited. RGIT Montrose On 12 February 2004, the Group acquired 100 per cent. of the issued and outstanding shares of RGIT, a leading provider of training and consultancy services to the upstream oil and gas exploration and production markets. Following the acquisition, RGIT changed its name to Petrofac Training Holdings Limited. Total consideration for the acquisition of the shares, inclusive of acquisition costs, was US$17.2 million. The fair value of the identifiable net assets and liabilities of RGIT acquired was US$3.7 million including US$11.0 million of property, plant and equipment, US$9.8 million of interest-bearing loan notes and US$0.6 million of cash and short-term deposits. The consideration was settled by a combination of cash and the issue of bank guaranteed loan notes. All of the loan notes had been redeemed in accordance with their terms by 30 June Rubicon Response On 28 January 2005, the Group acquired 100 per cent. of the issued and outstanding shares of Rubicon Response, a leading provider of emergency response management consultancy and training services to the upstream oil and gas exploration and production markets. Total consideration for the acquisition of the shares, inclusive of acquisition costs, was US$6.3 million in cash. The fair value of the net assets acquired was US$2.6 million, including US$2.3 million of cash and short-term deposits. 3. Recognition of revenues and profit and timing of cash flows Engineering & Construction The E&C Division s EPC contracts are typically undertaken on a fixed price or lump sum basis. Revenue is recognised to the extent that it is probable economic benefits will flow to the Group and the revenue can be reliably measured. As such, revenues from fixed price and modified fixed price contracts are recognised on the percentage-of-completion method, based on surveys of work performed. The Directors consider this to be the best available measure of progress on these contracts. Petrofac does not recognise profit on its lump sum contracts until a project has reached a threshold percentage of completion. The final profitability of a lump sum contract is assessed upon completion, with an allowance being made, where appropriate, for any anticipated liabilities during the warranty period. It is therefore not unusual for the profit recognition on a contract to lag the revenue recognition and, depending on execution risks during a contract s closing stages and the duration of any warranty periods, to be weighted towards the end of a contract. Revenues from cost-plus-fee contracts are recognised on the basis of costs incurred during the period plus the fee earned measured by the cost-to-cost method. Provision is made for all losses expected to arise on completion of contracts entered into at the balance sheet date, whether or not work has commenced on these contracts. 79

80 Incentive payments are included in revenue when the contract is sufficiently advanced and the amount of the incentive payments can be measured reliably. Claims are only included in revenue when negotiations have reached an advanced stage such that it is probable the claim will be accepted and can be measured reliably. Due to the nature of the business, revenues tend to vary year on year depending on the size of contract awards and the percentage completed during the year. The E&C Division s lump sum EPC contracts typically extend beyond a single financial year end and often beyond two years. The timing of cash flow realised during the course of a lump sum EPC contract does not necessarily closely follow the recognition of profit. This may be due to the receipt of advance payments from the client ahead of contract mobilisation, potentially significant cash outflows arising from procurement of major equipment and materials and also to the nature and timing of contractually determined milestone payments. The E&C Division s engineering service and consultancy contracts are typically undertaken on a reimbursable basis against an agreed schedule of rates, plus, in certain circumstances, incentive payments arising out of the performance according to specified KPIs. Certain contracts are undertaken on a fixed price basis and are recognised on the percentage of completion method, measured by milestones completed or earned value. The timing of cash flow realised by the engineering service and consultancy business is less volatile than for EPC contracts as a result of a smaller and more diversified contract base. Operations Services The OS Division s contracts are typically undertaken on a reimbursable basis against an agreed contract schedule of rates, plus, in certain circumstances, incentive payments arising out of the performance according to specified KPIs. Revenues from reimbursable contracts are recognised in the period in which the services are provided. Incentive payments are included in revenue when the contract is sufficiently advanced and the amount of the incentive payments can be measured reliably. Certain contracts are undertaken on a fixed price basis and are recognised on the percentage of completion method, measured by milestones completed or earned value. The majority of the OS Division s activities are undertaken in the UKCS. Typically, contractual terms require clients to promptly reimburse Petrofac for the services undertaken on behalf of the client. Often this can include procurement of materials and services which may represent a significant proportion of contract revenue and which may not attract a profit margin. The Directors believe that, because of the nature of the services provided, the facilities management and service operator contracts of the OS Division can be expected to have a lower variability of operating margins than the E&C contracts over the life of a contract. Resources The most significant producing asset in the Resources portfolio is Petrofac s 10 per cent. investment in the Ohanet development in Algeria. Under the terms of an RSC, Petrofac receives monthly remuneration and reimbursement over the term of its investment from first production which commenced in late October The only other current revenue producing asset is an investment in a crude oil refinery in Kyrgyzstan through a 50 per cent. interest in KPC, although in August 2005, Petrofac agreed to acquire a per cent. interest in the Hewett gas field in the UKCS. Completion of the acquisition is subject to the approval of the Hewett partners and the DTI. The Directors believe that production in 2005 from the Hewett field is averaging 35 million cubic feet per day (7.7 million cubic feet per day net sales gas to Petrofac, on the basis of its current ownership of the per cent. interest). Resources has a number of investments in development phase, the most significant of which is its 30 per cent. interest in a PSC for the Cendor PM-304 block in offshore peninsular Malaysia. The Cendor investment is scheduled to commence production in late Following approval of a field development plan in early 2005, Petrofac is presently procuring the major capital items required for development of the asset. Other development investments are interests in two UKCS fields for which studies are underway to determine the feasibility of economic development. For further information, see the description of these projects in paragraph 4 of Part III Information on the Petrofac Group. 80

81 Revenue generated by Resources investments is recognised to the extent that it is probable that economic benefit will flow to the Group and the revenue can be reliably measured. As such, oil and gas revenues comprise the Group s share of sales from the processing or sale of hydrocarbons on an entitlement basis. 4. Consolidation of joint ventures Petrofac sometimes forms joint ventures with other firms in the course of its work. Petrofac s interests in joint ventures are accounted for by proportionate consolidation, which involves recognising Petrofac s proportionate share of the joint venture s assets, liabilities, income and expenses on a line-by-line basis. In accordance with IFRS, the Group s proportionate share of its joint venture interests is also disclosed separately. 5. Accounting treatment of foreign currencies Petrofac s functional currency for financial reporting purposes is US$ since a significant proportion of the Group s assets, liabilities, income and expenses are US$ denominated. Notwithstanding this, there are a number of Group subsidiaries with non-us$ functional currencies. In particular, the Group s main trading subsidiaries with activities in the UKCS have Sterling functional currency. The balance sheets of subsidiaries and joint ventures with functional currencies other than US$ are translated using the closing rate method, whereby assets and liabilities are translated at the rates of exchange ruling at the balance sheet date. The income statements of such subsidiaries and joint ventures are translated at average exchange rates for the period. Exchange differences arising on the retranslation of net assets are taken directly to equity. In the accounts of individual Group companies, transactions in foreign currencies are recorded at the prevailing rate at the date of the transaction. At the period end, monetary assets and liabilities denominated in foreign currencies are retranslated at the rates of exchange prevailing at the balance sheet date. All foreign exchange gains and losses are taken to the income statement. The following table sets out the average exchange rates for US$ / Sterling for the 6 month periods ended 30 June 2005 and 2004 and the financial years of 2004, 2003 and 2002, and the period end exchange rates for US$/Sterling as at 30 June 2005 and 2004 and 2004, 2003 and 2002, used by Petrofac for its financial reporting. H H US$/ Average rate for the period Period end rate Backlog Petrofac uses the measurement of revenue backlog as a key performance indicator for its Engineering & Construction and Operations Services businesses. Backlog consists of the estimated revenue attributable to the uncompleted portion of lump sum EPC contracts and variation orders plus, with regard to engineering services and facilities management contracts, the estimated revenue attributable to the lesser of the remaining term of the contract or, in the case of life-of-field facilities management contracts, five years. To the extent work advances on these contracts, revenue is recognised and removed from the backlog. Where contracts extend beyond five years, the backlog relating thereto is incremented on a rolling monthly basis. Backlog includes only the revenue attributable to signed contracts for which all pre-conditions to entry have been met and only the proportionate share of joint venture contracts that is attributable to Petrofac. Backlog does not include any revenue expected to arise from contracts where the client has no commitment to draw upon services from the Group. With regard to certain of the Group s facilities management contracts, a substantial proportion of the revenue estimated to arise is subject to the level of capital and operational expenditure determined ultimately by the client. The actual revenue realised on such contracts may therefore differ from that originally estimated in calculating backlog. In addition, the backlog in relation to such contracts may differ from the values ascribed to such contracts by Petrofac at the time of contract award. In relation to such contracts, the backlog figure reflects, at any point in time, the 81

82 Group s best estimate of the future level of expenditure and hence revenue expected to arise over the lesser of five years or the remaining term of the contract. In addition, a significant proportion of the Group s revenue is denominated in Sterling. The backlog figure, reported in US$, includes the Sterling revenue converted into US$ at the prevailing period end exchange rate. Subsequent variations in the exchange rate will therefore vary the US$ backlog amount although the underlying Sterling backlog will remain unchanged. Backlog is not an audited measure. Other companies in the oil and gas industry may calculate this measure differently. See also Part II Risk factors. 7. Review of the financial results of the Petrofac Group 7.1 The Petrofac Group, overview The following table sets out selected financial information relating to the continuing operations of Petrofac. It has been extracted or derived without material adjustment from, and should be read in conjunction with, Part X Financial Information on Petrofac. H H (unaudited) US$ in thousands (unless stated otherwise) Total Revenue 692, , , , ,398 E&C 398, , , , ,684 OS 279, , , ,881 12,703 Resources 22,572 21,569 45,042 14,439 13,914 Consolidation and elimination (8,817) (4,104) (7,105) (3,489) (17,903) Growth/(decline) on prior period Total 71.8% 51.3% 60.6% E&C 111.9% 38.1% (10.4%) OS 41.8% 60.1% 2,063.9% Resources 4.7% 211.9% 3.8% Consolidation and elimination 114.8% 103.6% (80.5%) Operating profit/(loss) 41,081 32,453 68,283 37,747 35,296 E&C 22,867 15,170 33,524 30,529 37,669 OS 12,391 8,238 17,347 10, Resources 8,769 8,990 17,164 (1,805) 2,082 Consolidation and elimination (2,946) (1,150) (5,097) Operating Margin Total 5.9% 8.1% 7.2% 6.0% 9.0% E&C 5.7% 8.1% 7.1% 8.9% 9.8% OS 4.4% 4.2% 3.9% 3.7% 5.1% Resources 38.8% 41.7% 38.1% (12.5%) 15.0% Net profit/(loss)* 36,392 21,994 46,083 38,359 34,336 E&C 22,958 15,888 33,100 32,183 36,757 OS 7,294 4,275 9,643 6, Resources 12,034 3,552 6,953 1,579 2,396 Consolidation and elimination (5,894) (1,721) (3,613) (2,219) (5,257) Net Margin Total 5.3% 5.5% 4.8% 6.1% 8.8% E&C 5.8% 8.4% 7.0% 9.4% 9.6% OS 2.6% 2.2% 2.2% 2.5% 3.5% Resources 53.3% 16.5% 15.4% 10.9% 17.2% EBITDA 54,346 45,143 96,065 48,075 39,043 E&C 28,055 18,808 41,880 34,254 40,217 OS 13,296 9,737 21,135 11, Resources 15,730 16,354 32,289 2,572 2,716 Consolidation and elimination (2,735) (365) (4,600) EBITDA Margin Total 7.8% 11.2% 10.1% 7.6% 10.0% E&C 7.0% 10.0% 8.8% 10.0% 10.5% OS 4.8% 4.9% 4.8% 4.2% 5.6% Resources 69.7% 75.8% 71.7% 17.8% 19.5% * attributable to Petrofac shareholders 82

83 7.2 The Petrofac Group, 6 months ended 30 June 2005 compared with unaudited 6 months ended 30 June 2004 Revenues Revenues increased by 71.8 per cent. to US$692.4 million (H : US$403.0 million), reflecting the following changes at a divisional level: Revenues arising from the E&C Division increased by per cent. to US$399.0 million (H1 2004: US$188.3 million) reflecting progress made on contracts that were either at an early stage of completion during H or were awarded in H Revenues arising from the OS Division increased by 41.8 per cent. to US$279.7 million (H1 2004: US$197.2 million) with growth experienced across all business areas reflecting, in particular, in the UKCS, a new service operator contract and increased revenues from the other services and, outside the UKCS, a new maintenance management contract in Kuwait. Revenues arising from the Resources Division increased to US$22.6 million (H1 2004: US$21.6 million) reflecting an increase in the Division s share of revenue from the KPC joint venture offset by a reduction in revenues from the Ohanet investment (H having benefited from revenue catch-up in accordance with the terms of the RSC arising from lower production levels during start-up in late 2003). Inter-divisional revenues eliminated on consolidation for the period were US$8.8 million (H1 2004: US$ 4.1 million). Selling, general and administrative expenses Selling, general and administrative expenses (SG&A) increased to US$34.1 million (H1 2004: US$29.0 million), representing 4.9 per cent. of revenues (H1 2004: 7.2 per cent.). The increase in SG&A includes US$2.3 million of legal and professional expenses in relation to the Company s listing on the London Stock Exchange, as well as an increase in expenses in the E&C and OS Divisions reflecting the continued growth of the business. Other operating income and expenses Other operating income, net of other operating expenses, amounted to US$0.9 million, net (H1 2004: US$3.6 million, net) and included gains made on the sale of certain investments held by the Resources Division of US$1.8 million (H1 2004: US$2.4 million), other income of US$0.2 million, net (H1 2004: US$0.8 million, net), offset by net foreign exchange losses of US$1.1 million (H1 2004: net foreign exchange gains US$0.4 million). Operating profit Operating profit increased by 26.6 per cent. to US$41.1 million (H1 2004: US$32.5 million), representing 5.9 per cent. of revenues (H1 2004: 8.1 per cent.), reflecting the following changes at a divisional level: Operating profit arising from the E&C Division increased by 50.7 per cent. to US$22.9 million (H1 2004: US$15.2 million), representing a margin of 5.7 per cent. (H1 2004: 8.1 per cent.). The reduction in operating margin in H as compared to H reflected the lower overall risk profile (and therefore margin) of those contracts generating revenues during the period, fewer contracts reaching completion (with profit recognition being typically back-end weighted), and a further provision on the BTC/SCP contract. Operating profit arising from the OS Division increased by 50.4 per cent. to US$12.4 million (H1 2004: US$8.2 million), representing a margin of 4.4 per cent. (H1 2004: 4.2 per cent.). The improvement in operating margin as compared to H was primarily attributable to lower SG&A costs (including the cessation of goodwill amortisation from the beginning of 2005) as a percentage of revenue in H Operating profit arising from the Resources Division decreased marginally to US$8.8 million (H1 2004: operating profit US$9.0 million), representing a margin of 38.8 per cent. (H1 2004: 41.7per cent.). 83

84 In addition, unallocated corporate costs, net of unallocated operating profits increased to US$2.9 million (H1 2004: US$0.1 million, net unallocated income). The increase is primarily attributable to accrued legal and professional expenses in relation to the Company s listing on the London Stock Exchange. Finance income and charges Net interest payable by the Group in H was US$3.4 million (H1 2004: US$2.5 million). The increase in interest costs as compared to H is mainly attributable to an increase in the level of term loan borrowings within the Group, following the share buyback in October 2004, an increase in the interest payable to 3i on the variable rate unsecured loan notes prior to their conversion into ordinary shares in June 2005 and an increase in benchmark US interest rates. The increase was partly offset by lower interest costs associated with Ohanet. For the period ended 30 June 2005, net interest cover (being profit from continuing operations before tax and finance costs divided by net finance costs) was 12.1 times (H1 2004: 13.1 times). Tax The income tax charge as a percentage of profit before tax in H was 3.4 per cent. (H1 2004: 26.8 per cent.). The effective rate of tax decreased in H as compared to H largely as a result of recognising a tax credit of US$7.6 million relating to the Cendor project. This tax credit arose on losses that became available for tax relief in H following the approval of the field development plan in relation to Block PM-304, Malaysia. In addition, in H a UK deferred tax charge within the OS Division relating to unremitted dividends from overseas subsidiaries was recognised; there was no corresponding charge in H Net profits Net profits attributable to Petrofac shareholders increased by 65.5 per cent. to US$36.4 million (H1 2004: US$22.0 million), representing 5.3 per cent. of revenues (H1 2004: 5.5 per cent.), reflecting the changes noted above. At a divisional level: Net profits arising from the E&C Division increased by 44.5 per cent. to US$23.0 million (H1 2004: US$15.9 million), representing a margin of 5.8 per cent. (H1 2004: 8.4 per cent.), reflecting primarily the decline in operating margin (as described above) but also an increase in the effective rate of tax in H as compared to H1 2004, with a greater proportion of business being executed in taxable jurisdictions. Net profits arising from the OS Division increased by 70.6 per cent. to US$7.3 million (H1 2004: US$4.3 million), representing a margin of 2.6 per cent. (H1 2004: 2.2 per cent.). The increase in net margin in H as compared with H was attributable to an improvement in the operating margin (as described above) and a reduction in the effective rate of tax. Net profits arising from the Resources Division increased to US$12.0 million (H1 2004: US$3.6 million), representing a margin of 53.3 per cent. (H1 2004: 16.5 per cent.). The increase on H principally reflects the benefit of a tax credit of US$7.6 million from the Division s investment in Cendor. In addition, interest costs were lower in H as a result of the progressive repayment of project finance loans relating to the Division s Ohanet investment. On a fully diluted basis, adjusting for the impact of the unsecured loan notes, net profits from continuing operations attributable to shareholders increased by 61.3 per cent. to US$37.7 million (H1 2004: US$23.3 million), representing 5.4 per cent. of revenues (H1 2004: 5.8 per cent.). EBITDA EBITDA increased to US$54.3 million (H1 2004: US$45.1 million), representing 7.8 per cent. of revenues (H1 2004: 11.2 per cent.). The increase in EBITDA is attributable to the E&C and OS Divisions, partly offset by the unallocated Group charge of US$2.3 million for legal and professional expenses in relation to the Company s listing on the London Stock Exchange and a fall of US$0.6 million in EBITDA for the Resources Division. The decline in the EBITDA margin is principally attributable to a decline in the relative proportion of EBITDA from the Resources Division, a fall in the EBITDA margin of the E&C Division (relating mainly to the fall in operating margin as described above) and the increase in unallocated Group charge. 84

85 Backlog The combined backlog of the E&C and OS Divisions as at 30 June 2005 was approximately US$2,494 million, representing an increase of 43.3 per cent. on the comparable figure as at The backlog of the E&C Division as at 30 June 2005 was approximately US$1,041 million, representing an increase of 40.9 per cent. on the comparable figure as at The backlog of the OS Division as at 30 June 2005 was approximately US$1,453 million, representing an increase of 45.2 per cent. on the comparable figure as at The Petrofac Group, 2004 financial year compared with 2003 financial year Revenues Revenues increased by 51.3 per cent. to US$951.5 million (2003: US$628.7 million), reflecting the following changes at a divisional level: Revenues arising from the E&C Division increased by 38.1 per cent. to US$473.5 million (2003: US$342.9 million) reflecting a combination of new contract awards during the year, revenue recognition on prior year contract awards, partially offset by lower overall revenues from existing contracts approaching completion. Revenues arising from the OS Division increased by 60.1 per cent. to US$440.1 million (2003: US$274.9 million) reflecting a full year s contribution from new business secured during 2003, in particular the new service operator contracts, growth in the operations services business and expansion of the non-ukcs business and revenues arising from RGIT, acquired in February An increase of approximately 10 per cent. in the average value of Sterling against the US$ during the period also contributed to the revenue increase. Revenues arising from the Resources Division increased to US$45.0 million (2003: US$14.4 million) reflecting principally a full year s contribution from the Ohanet development which commenced production in late October Inter-divisional revenues eliminated on consolidation for the year were US$7.1 million (2003: US$3.5 million). Selling, general and administrative expenses Selling, general and administrative expenses (SG&A) increased to US$58.8 million (2003: US$38.7 million), representing 6.2 per cent. of revenues (2003: 6.2 per cent.). The increase in SG&A reflects an increase in indirect costs in all parts of the business reflecting the continued growth of the business. Other operating income and expenses Other operating income, net of other operating expenses, amounted to US$4.7 million (2003: US$1.9 million, net) and included gains made on the sale of certain investments held by the Resources Division of US$2.9 million (2003: nil), other income of US$1.1 million, net (2003: US$1.1 million, net) and net foreign exchange gains of US$0.6 million (2003: US$0.8 million). Operating profit Operating profit increased by 80.9 per cent. to US$68.3 million (2003: US$37.7 million), representing 7.2 per cent. of revenues (2003: 6.0 per cent.), reflecting the following changes at a divisional level: Operating profit arising from the E&C Division increased by 9.8 per cent. to US$33.5 million (2003: US$30.5 million), representing a margin of 7.1 per cent. (2003: 8.9 per cent.), reflecting a combination of profit recognition on new contract awards during the year, the reversal of certain cost provisions relating to projects that completed during the year but did not contribute significantly to revenues and a provision made in relation to the BTC/SCP project, which represented a significant proportion of the year s revenues. 85

86 Operating profit arising from the OS Division increased by 70.5 per cent. to US$17.3 million (2003: US$10.2 million), representing a margin of 3.9 per cent. (2003: 3.7 per cent.). The improvement in operating margin as compared to 2003 was partly attributable to the higher margin contribution from service operator contracts and from RGIT, partly offset by a higher depreciation and amortisation charge, arising principally from the RGIT acquisition. Operating profit arising from the Resources Division increased to US$17.2 million (2003: operating loss US$1.8 million), representing a margin of 38.1 per cent. (2003: negative 12.5 per cent.), reflecting principally a full year s contribution from the investment in the Ohanet development (2003: 2 months) included a write-down in value of the KPC investment. In addition to the above divisional factors, unallocated corporate income increased to US$0.8 million (2003: unallocated corporate costs US$0.6 million). Finance income and charges Net interest payable by the Group in 2004 was US$5.5 million (2003: nil). The increase in interest cost as compared to 2003 includes the impact of: a full year of interest on project finance for the Ohanet investment which was being capitalised in the period before project completion; interest cost on assumed loans and borrowings following the acquisition of RGIT and incurred in conjunction with the buy back in October 2004 of approximately 25 per cent. of the Company s then issued share capital; and an increase in interest rates in the UK and US. For the period ended 2004, net interest cover was 12.3 times (2003: net interest payable nil). Tax The income tax charge as a percentage of profit before tax in 2004 was 26.6 per cent. (2003: 6.8 per cent.). The effective rate of tax increased in 2004 as compared to 2003 as a result of a greater proportion of profits being generated in higher income tax jurisdictions and is largely attributable to: a full year of income from the Ohanet investment, Algeria, which is taxed at 38 per cent.; additional withholding taxes on several projects executed in the year; and an increase in the proportion of income from UK operations, where the income tax rate is 30 per cent. Net profits Net profits attributable to Petrofac shareholders increased by 20.1 per cent. to US$46.1 million (2003: US$38.4 million), representing 4.8 per cent. of revenues (2003: 6.1 per cent.) and reflecting the changes noted above. At a divisional level: Net profits arising from the E&C Division increased by 2.8 per cent. to US$33.1 million (2003: US$32.2 million), representing a margin of 7.0 per cent. (2003: 9.4 per cent.), reflecting the lower operating margin (as described above) and the increased income tax charge attributable to local taxation payable on certain EPC contracts. Net profits arising from the OS Division increased by 41.5 per cent. to US$9.6 million (2003: US$6.8 million), representing a margin of 2.2 per cent. (2003: 2.5 per cent.). Notwithstanding the higher operating margin in 2004 as compared with 2003, the net income margin in 2004 declined due to higher interest and tax charges. Net profits arising from the Resources Division increased to US$7.0 million (2003: US$1.6 million), representing a margin of 15.4 per cent. (2003: 10.9 per cent.). The increase on 2003 reflects the full year contribution from the Ohanet development, net of tax, partly offset by an increase in net interest payable on project finance (previously capitalised). 86

87 On a fully diluted basis, adjusting for the impact of the unsecured loan notes, net profits attributable to shareholders increased by 23.3 per cent. to US$48.7 million (2003: US$39.5 million), representing 5.1 per cent. of revenues (2003: 6.3 per cent.). EBITDA EBITDA increased to US$96.1 million (2003: US$48.1 million), representing 10.1 per cent. of revenues (2003: 7.6 per cent.). The increase in EBITDA margin reflected principally the full year s contribution from the Resources Division s investment in the Ohanet development which has a significantly higher EBITDA margin than the rest of Petrofac s activities and an increase in the OS Division s EBITDA margin, partly offset by a fall in the E&C Division s EBITDA margin. Backlog The combined backlog of the E&C and OS Divisions as at 2004 was approximately US$1,740 million, representing an increase of 58.6 per cent. on the comparable figure as at The backlog of the E&C Division as at 2004 was approximately US$739 million, representing an increase of per cent. on the comparable figure as at The backlog of the OS Division as at 2004 was approximately US$1,001 million, representing an increase of 26.9 per cent. on the comparable figure as at The Petrofac Group, 2003 financial year compared with 2002 financial year Revenues Revenues increased by 60.6 per cent. to US$628.7 million (2002: US$391.4 million), reflecting the following changes at a divisional level: Revenues arising from the E&C Division decreased by 10.4 per cent. to US$342.9 million (2002: US$382.7 million) reflecting a combination of lower overall revenues from existing contracts, many of which were at a high level of completion at the beginning of the year, countered by new contract awards during the year, including the BTC/SCP contract. Revenues arising from the OS Division increased to US$274.9 million (2002: US$12.7 million). PGS PS, which became the core of the OS Division, was acquired by Petrofac on 11 December 2002 and, consequently, revenues during 2002 were only for 20 days trading. During 2003, the OS Divisions revenues were generated largely by established contracts with additional revenue arising from transition work undertaken on new service operator contracts prior to the contracts reaching full facilities management status. Revenues arising from the Resources Division increased to US$14.4 million (2002: US$13.9 million) reflecting revenues arising from the initial production from the Ohanet development, which commenced in late October 2003, partly offset by a fall in revenues from facilities management contracts that concluded during the year. Inter-divisional revenues eliminated on consolidation for the period were US$ 3.5 million (2002: US$17.9 million). Selling, general and administrative expenses Selling, general and administrative expenses increased to US$38.7 million (2002: US$23.0 million), representing 6.2 per cent. of revenues (2002: 5.9 per cent.). The increase in SG&A mainly reflects a full year of costs for PGS PS following its acquisition in December 2002 (2002: 20 days). Other operating income and expenses Other operating income, net of other operating expenses, amounted to US$1.9 million (2002: US$2.8 million) and included US$1.1 million of other income, net (2002: US$ 1.1 million, net) and net foreign exchange gains of US$0.8 million (2002: US$1.7 million). 87

88 Operating profit Operating profit increased by 6.9 per cent. to US$37.7 million (2002: US$35.3 million), representing 6.0 per cent. of revenues (2002: 9.0 per cent.), reflecting the following changes at a divisional level: Operating profit arising from the E&C Division decreased by 19.0 per cent. to US$30.5 million (2002: US$37.7 million), representing a margin of 8.9 per cent. (2002: 9.8 per cent.), reflecting principally the decline in revenues over 2002 and no profit recognition on the early stages of the BTC/SCP contract, which represented a significant proportion of revenue for the year. In addition, depreciation and amortisation increased due principally to property, plant and equipment acquired in support of the BTC/SCP joint venture contract. Operating profit arising from the OS Division was US$10.2 million, representing a margin of 3.7 per cent. In 2002 operating profit was US$0.6 million, representing a margin of 5.1 per cent. (reflecting 20 days of trading after the acquisition of PGS PS). Operating loss arising from the Resources Division was US$1.8 million (2002: profit of US$2.1 million), reflecting the impact of revenue factors, discussed above, and an impairment charge on the Group s investment in KPC. In addition to the above divisional factors, unallocated corporate costs reduced to US$0.6 million (2002: US$1.9 million). Finance income and charges Net interest payable by the Group in 2003 was nil (2002: US$0.9 million net interest receivable). For the period ended 2003, net interest cover was not a meaningful measure on the basis the Group had net interest income of US$0.03 million for the period (2002: net interest income of US$0.9 million). Tax The income tax charge as a percentage of profit before tax in 2003 was 6.8 per cent. (2002: 6.0 per cent.). The rate of tax in both years reflects the fact that a significant proportion of the Group s activities were undertaken in countries where income tax was not levied. Net profits Net profits attributable to Petrofac shareholders increased by 11.7 per cent. to US$38.4 million (2002: US$34.3 million), representing 6.1 per cent. of revenues (2002: 8.8 per cent.), reflecting the following changes at a divisional level: Net profits arising from the E&C Division decreased by 12.4 per cent. to US$32.2 million (2002: US$36.8 million), representing a margin of 9.4 per cent. (2002: 9.6 per cent.). Net profits arising from the OS Division were US$6.8 million (2002: US$0.4 million), representing a margin of 2.5 per cent. (2002: 3.5 per cent.), with the 2002 figures reflecting 20 days of trading after the acquisition of PGS PS. Net profits arising from the Resources Division decreased by 34.1 per cent. to US$1.6 million (2002: US$2.4 million), representing a margin of 10.9 per cent. (2002: 17.2 per cent.), reflecting the impairment of KPC, partly offset by a minority interest credit relating to the impairment and a small tax credit of US$0.2 million (2002: nil). On a fully diluted basis, net profits attributable to Petrofac shareholders increased by 13.5 per cent. to US$39.5 million (2002: US$34.8 million), representing 6.3 per cent. of revenues (2002: 8.9 per cent.). EBITDA EBITDA increased to US$48.1 million (2002: US$39.0 million), representing 7.6 per cent. of revenues (2002: 10.0 per cent.) The decline in the EBITDA margin reflected primarily the impact of a full year s contribution from the PGS PS business which has lower EBITDA margins (2002: 20 days). 88

89 Backlog The combined revenue backlog of the E&C and OS Divisions as at 2003 was approximately US$1,097 million, representing an increase of 24.0 per cent. on the comparable figure as at The backlog of the E&C Division as at 2003 was approximately US$308 million, representing a decrease of 11.5 per cent. on the comparable figure as at The backlog of the OS Division as at 2003 was approximately US$789 million, representing an increase of 46.9 per cent. on the comparable figure as at Review of the financial results of Engineering & Construction 8.1 Overview The E&C Division provides services to oil and gas clients to develop, design and construct facilities, including: integrated engineering, procurement and construction services, including project management, engineering, procurement services and the construction management and commissioning of oil and gas facilities; and specialist engineering and consultancy services, including preparation of field development plans and associated studies, design development, FEED, demanning and decommissioning studies, and the provision of risk, safety and environmental consultancy services. Engineering and consultancy services are usually provided on a cost reimbursable basis, while major EPC contracts are usually undertaken on a lump sum basis. During the 6 months ended 30 June 2005, the E&C Division achieved total revenues of US$399.0 million (57.6 per cent. of Group revenues), operating profit of US$22.9 million (55.7 per cent. of Group operating profit) and net profits of US$23.0 million (63.1 per cent. of Group net profits). EBITDA for the period was US$28.1 million (51.6 per cent. of Group EBITDA). The following table sets out selected financial information of the Engineering & Construction Division of Petrofac. It has been extracted or derived without material adjustment from, and should be read in conjunction with Part X Financial Information on Petrofac. H H (unaudited) US$ in thousands (unless stated otherwise) Total Revenue 398, , , , ,684 Growth/(decline) on prior period 111.9% 38.1% (10.4%) Operating profit 22,867 15,170 33,524 30,529 37,669 Net profits 22,958 15,888 33,100 32,183 36,757 EBITDA 28,055 18,808 41,880 34,254 40,217 Operating Margin 5.7% 8.1% 7.1% 8.9% 9.8% Net Margin 5.8% 8.4% 7.0% 9.4% 9.6% EBITDA Margin 7.0% 10.0% 8.8% 10.0% 10.5% 8.2 Engineering & Construction 6 months ended 30 June 2005 compared with unaudited 6 months ended 30 June 2004 Revenues during the period increased by per cent. to US$399.0 million (H1 2004: US$188.3 million) reflecting continuing progress being made on various Engineering and Procurement (EP) and EPC contracts, including Kashagan, BTC/SCP, QP and Crescent, and the later timing of EPC 89

90 awards secured during the course of The top five contracts (by revenue) contributed, in aggregate, approximately 90 per cent. (H1 2004: 91 per cent.) of divisional revenue with the top two contracts contributing, in aggregate, approximately 67 per cent. (H1 2004: 84 per cent.) of divisional revenue. Operating profit increased by 50.7 per cent. to US$22.9 million (H1 2004: US$15.2 million), representing a margin of 5.7 per cent. (H1 2004: 8.1 per cent.). The reduction in operating margin in H as compared to H reflected a combination of factors, including: contracts generating revenues during H having different margin characteristics than those generating revenues during H1 2004, specifically, the Kashagan EP contract (awarded in H2 2004), being of lower risk than typical EPC contracts, generating a lower margin and representing a significant proportion of revenues in H1 2005; the number and timing of contracts reaching completion during the period, specifically, H saw greater profit recognition on completed contracts than H (with neither contributing significantly to revenues); and a further provision on the BTC/SCP contract which generated lower revenues than the prior comparable period reflecting the contract approaching completion. Net profits increased by 44.5 per cent. to US$23.0 million (H1 2004: US$15.9 million), representing a margin of 5.8 per cent. (H1 2004: 8.4 per cent.). The decline in net margin over and above the reduction in operating margin primarily reflects an increased income tax charge, with a greater proportion of business being executed in taxable jurisdictions. EBITDA increased to US$28.1 million (H1 2004: US$18.8 million), representing a margin of 7.0 per cent. (H1 2004: 10.0 per cent.), relating mainly to the fall in operating margin, as discussed above. The total backlog for the E&C Division as at 30 June 2005 was approximately US$1,041 million, representing an increase of 40.9 per cent. on the comparable figure as at During the 6 month period, new contract awards included a major lump sum EPC contract in Kuwait (KOC) with a value of US$644 million. 8.3 Engineering & Construction 2004 financial year compared with 2003 financial year Revenues during the year increased by 38.1 per cent. to US$473.5 million (2003: US$342.9 million) reflecting increased revenue generated by the BTC/SCP contract, revenue generated by new contracts awarded during the year, including QP and Crescent in H and Kashagan in H2 2004, partly offset by lower overall revenues generated by other existing contracts, many of which were approaching completion at the beginning of the year. The top five contracts (by revenue) contributed, in aggregate, approximately 86 per cent. (2003: 78 per cent.) of divisional revenue with the top two contracts contributing, in aggregate, approximately 67 per cent. (2003: 56 per cent.) of divisional revenue and no other contract contributing more than 10 per cent. Operating profit increased by 9.8 per cent. to US$33.5 million (2003: US$30.5 million), representing a margin of 7.1 per cent. (2003: 8.9 per cent.). The reduction in operating margin in FY 2004 as compared to FY 2003 reflected a combination of factors including: profit recognition on certain of the current contracts and new awards secured during the year and also on certain contracts that reached completion during the period (which did not make a significant contribution to revenues); a significant provision made on the BTC/SCP contract, which generated a significant proportion of revenues during the period; no profit recognition on the Kashagan EP contract, reflecting its early stage of completion as at the year end; and an increase in depreciation and amortisation for the period relating principally to property, plant and equipment acquired in support of the BTC/SCP contract (2004: US$8.4 million vs 2003: US$3.7 million), representing 1.8 per cent. of revenues (2003: 1.1 per cent.). 90

91 Net profits increased by 2.8 per cent. to US$33.1 million (2003: US$32.2 million), representing a margin of 7.0 per cent. (2003: 9.4 per cent.). The decline in net margin over and above the reduction in operating margin primarily reflected an increased income tax charge of US$2.3 million (2003: US$0.5 million, tax credit), attributable to local taxation arising on certain EPC contracts and withholding taxes on the division s engineering services activities. EBITDA increased to US$41.9 million (2003: US$34.3 million), representing a margin of 8.8 per cent. (2003: 10.0 per cent.). The decline in EBITDA margin related mainly to the fall in operating margin, as discussed above. The total backlog for the E&C Division as at 2004 was approximately US$739 million, representing an increase of per cent. on the comparable figure as at the end of New lump sum EPC contracts with an aggregate value of approximately US$800 million were awarded during the year, including Kashagan (value: US$514 million), Qatar Petroleum (value: US$173 million) and Crescent Petroleum (value: US$82 million). 8.4 Engineering & Construction 2003 financial year compared with 2002 financial year Revenues during the year decreased by 10.4 per cent. to US$342.9 million (2002: US$382.7 million) reflecting a full year s contribution from the BTC/SCP contract and revenues from new contract awards during the year, offset by a net decline in the revenues arising from other existing contracts, many of which were near completion at the beginning of the year. The top five contracts (by revenue) contributed, in aggregate, approximately 78 per cent. of divisional revenue (2002: 85 per cent.) with two contracts (2002: four) contributing, in aggregate, approximately 56 per cent. of divisional revenue (2002: 81 per cent.) and no other contract contributing more than 10 per cent. Operating profit decreased by 19.0 per cent. to US$30.5 million (2002: US$37.7 million), representing a margin of 8.9 per cent. (2002: 9.8 per cent.), reflecting principally the decline in revenues over 2002 and no profit recognition on the early stages of the BTC/SCP contract which represented a significant proportion of the revenue for the year. In addition, depreciation and amortisation increased to US$3.7 million (2002: US$2.5 million), representing 1.1 per cent. of revenues (2002: 0.7 per cent.), relating principally to property, plant and equipment acquired in support of the BTC/SCP contract. Net profits decreased by 12.4 per cent. to US$32.2 million (2002: US$36.8 million), representing a margin of 9.4 per cent. (2002: 9.6 per cent.). The year on year decline in net margin was less than the decline in operating margin due to an income tax credit of US$0.5 million, comprising a tax charge on EPC activities offset by a tax credit from the division s engineering services activities in the UK. EBITDA decreased to US$34.3 million (2002: US$40.2 million), representing a margin of 10.0 per cent. (2002: 10.5 per cent.), reflecting the same factors as affected operating profit, as discussed above. The total backlog for the E&C Division as at 2003 was approximately US$308 million, representing a decrease of 11.5 per cent. on the comparable figure as at the end of New lump sum EPC awards during the year with an aggregate value of approximately US$117 million, including an engineering services and procurement contract for Agip (value: US$25 million) and the Diffra contract in Sudan (value: US$46 million). In addition, variations to the BTC/SCP contract amounted to US$134 million relating mainly to assigned orders. 9. Review of the financial results of Operations Services 9.1 Overview The OS Division provides services to oil and gas clients to operate, maintain and modify facilities and train personnel, including: facilities operations and maintenance services to the oil and gas industry for onshore and offshore installations, principally in the UKCS but with an increasing presence outside the UKCS, including the provision of operations management, maintenance services and consultancy, brownfield engineering services and specialist manpower; and 91

92 specialist training and human resource development for the oil and gas industry, including: safety training; operations and technical training; emergency response and critical incident management training; and training support and management services. The Group s facilities operations and maintenance services are typically provided under long term, cost reimbursable contracts, which include performance related remuneration, while the basis of remuneration for the Group s training services varies depending on the scope of the services being provided by the Group. During the 6 months ended 30 June 2005, the OS Division achieved total revenues of US$279.7 million (40.4 per cent. of Group revenues), operating profit of US$12.4 million (30.2 per cent. of Group operating profit) and net profits of US$7.3 million (20.0 per cent. of Group net profits). EBITDA for the period was US$13.3 million (24.5 per cent. of Group EBITDA). The following table sets out selected financial information of the Operations Services Division of Petrofac. It has been extracted or derived without material adjustment from, and should be read in conjunction with Part X Financial Information on Petrofac. H H (unaudited) US$ in thousands (unless stated otherwise) Total Revenue 279, , , ,881 12,703 Growth on prior period 41.8% 60.1% 2,063.9% Operating profit 12,391 8,238 17,347 10, Net profits 7,294 4,275 9,643 6, EBITDA 13,296 9,737 21,135 11, Operating Margin 4.4% 4.2% 3.9% 3.7% 5.1% Net Margin 2.6% 2.2% 2.2% 2.5% 3.5% EBITDA Margin 4.8% 4.9% 4.8% 4.2% 5.6% 9.2 Operations Services 6 months ended 30 June 2005 compared with unaudited 6 months ended 30 June 2004 Revenues for H increased by 41.8 per cent. to US$279.7 million (H1 2004: US$197.2 million) with growth experienced across all business areas reflecting, in particular, in the UKCS, the new service operator contract with Lundin and increased revenues from the provision of specialist manpower services and brownfield engineering services and, outside the UKCS, the new maintenance management contract with Kuwait Oil Company (KOC). The top five clients (by revenue) contributed, in aggregate, 43 per cent. of divisional revenues for the period (H1 2004: 51 per cent.), with two clients contributing more than 10 per cent. to the period s revenue (H1 2004: two). Operating profit increased by 50.4 per cent. to US$12.4 million (H1 2004: US$8.2 million), representing a margin of 4.4 per cent. (H1 2004: 4.2 per cent.). The improvement in operating margin as compared to H reflected a combination of higher pass-through revenues diluting margin offset by lower SG&A charges as a percentage of revenues, including a lower depreciation and amortisation charge of US$0.9 million (H1 2004: US$1.5 million) arising from the cessation of goodwill amortisation in H pursuant to IFRS 3. Net profits increased by 70.6 per cent. to US$7.3 million (H1 2004: US$4.3 million), representing a margin of 2.6 per cent. (H1 2004: 2.2 per cent.). In addition to the lower depreciation and amortisation charge noted above, the increase in the net margin was attributable to a fall in the effective tax rate in H1 2005, partially offset by a small increase in net interest payable. The effective tax rate fell to 35.7 per cent. in H compared with 45.0 per cent. in H The tax charge in H was adversely affected by a UK deferred tax charge recognised on unremitted dividends from an overseas subsidiary as well as proportionately higher overseas taxation. EBITDA increased by 36.6 per cent. to US$13.3 million (H1 2004: US$9.7 million), representing a margin of 4.8 per cent. (H1 2004: 4.9 per cent.). The decline in EBITDA margin as compared to H reflected the factors affecting the operating margin, as discussed above. 92

93 The total backlog for the OS Division as at 30 June 2005 was approximately US$1,453 million, representing an increase of 45.2 per cent. on the comparable figure at During the period, the OS Division secured new contracts and contract renewals with an aggregate value of US$733 million, with new awards including a service operator contract with Lundin in the UKCS (value: US$250 million), an operations and maintenance contract with Total in the UKCS (value: US$70 million), and a maintenance management contract with KOC (value US$125 million) and contract renewals including Mobil (value: US$48 million) and Sea Production (in relation to Galley asset) (value US$26 million). 9.3 Operations Services 2004 financial year compared with 2003 financial year Revenues for 2004 increased by 60.1 per cent. to US$440.1 million (2003: US$274.9 million) reflecting, inter alia, a full year s contribution from new business secured during 2003, in particular the new service operator contracts, growth in the operations services business, in particular from the provision of specialist manpower services, and expansion of the non-ukcs business. RGIT Montrose, acquired in February 2004, also made a significant contribution to the growth in revenues from 2003 to The increase in US$ reported revenues was also partly attributable to an appreciation of approximately 10 per cent. in the average value of Sterling against the US$ during the period. The top five clients (by revenue) contributed, in aggregate, 46 per cent. of divisional revenues for the year (2003: 57 per cent.), with only one client contributing more than 10 per cent. to the year s revenue (2003: two). Operating profit increased by 70.5 per cent. to US$17.3 million (2003: US$10.2 million), representing a margin of 3.9 per cent. (2003: 3.7 per cent.). The improvement in operating margin as compared to 2003 was partly attributable to higher margins arising primarily from the new service operator contracts and the new training business partly offset by higher SG&A costs, including an increased depreciation and amortisation charge of US$3.8 million, (2003: US$1.4 million) relating to the acquisition of RGIT. Net profits increased by 41.5 per cent. to US$9.6 million (2003: US$6.8 million), representing a margin of 2.2 per cent. (2003: 2.5 per cent.). Notwithstanding the higher operating margin achieved in 2004 compared to 2003, the decline in net margin in 2004 as compared with 2003 was attributable to higher interest and tax charges. Net interest payable increased to US$1.0 million (2003: nil) as a result of the debt assumed with both the acquisition of RGIT and increased working capital associated with the expansion of the non-ukcs business. The effective tax charge for the year increased to 40.9 per cent. of profit before tax (2003: 32.6 per cent.), reflecting a higher proportion of profits being generated in higher income tax jurisdictions, where withholding taxes were payable on certain contract revenues and as a result of providing deferred tax on unremitted dividends from an overseas subsidiary. EBITDA increased by 82.0 per cent. to US$21.1 million (2003: US$11.6 million), representing a margin of 4.8 per cent. (2003: 4.2 per cent.). The increase in EBITDA margin reflected the factors affecting the operating margin, as discussed above. The total backlog for the OS Division as at 2004 was approximately US$1,001 million, representing an increase of 26.9 per cent. on the comparable figure at During the period, the OS Division secured new contracts and contract renewals with an aggregate value of US$671 million, with new awards including brownfield engineering support for Lundin in the UKCS (value: US$13 million) and maintenance, management and operations contracts with SPGC in Iran (value not disclosed) and GNPOC in Sudan (value: US$40 million), and renewals including contracts with BHP Billiton (value: US$114 million), BG Armada (value not disclosed) and Sea Production (in relation to the Galley asset) (value not disclosed). 9.4 Operations Services 2003 financial year compared with 2002 financial year PGS PS, which became the core of the OS Division, was acquired by Petrofac on 11 December 2002 and, as such, contributed only 20 days trading to revenues for the 2002 financial year. 93

94 Revenues for 2003 were US$274.9 million (2002: US$12.7 million) generated largely by established contracts with additional revenue arising from transitional services provided ahead of taking on the full facilities management of three new service operator contracts. The top five clients (by revenue) contributed, in aggregate 57 per cent. of total revenues for the year (2002: 65 per cent.), with two clients contributing more than 10 per cent. to the year s revenue (2002: one). Operating profit was US$10.2 million, representing a margin of 3.7 per cent., after depreciation and amortisation of US$1.4 million. Net profit was US$6.8 million, representing a margin of 2.5 per cent., and reflected an income tax charge of US$3.3 million (32.6 per cent. of profit before tax). EBITDA increased to US$11.6 million, representing a margin of 4.2 per cent. The total backlog for the OS Division as at 2003 was approximately US$789 million, representing an increase of 46.9 per cent. on the comparable figure at During the period, the OS Division secured new contracts and contract renewals with an aggregate value of US$527 million, with new awards including service operator contracts with Tullow Oil & Gas (value not disclosed) and Venture Production (value: US$64 million) in the UKCS, a facilities management contract for a crude refinery in Papua New Guinea (value not disclosed), a facilities management contract relating to the Baku training centre (value not disclosed) and a renewal of the division s contract with Britannia (value: US$66 million). 10. Review of the financial results of Resources 10.1 Overview In selected situations, the Resources Division invests alongside its clients and partners in producing and proven or probable but not fully developed oil and gas reserves and energy infrastructure. Investments are assessed on the basis of their projected financial return reflecting the anticipated risks of the investment and, independently, the opportunity offered for the Group to provide services to its clients and partners. As at 30 June 2005, the Group s investments had a book equity value of US$96.6 million. During the 6 months ended 30 June 2005, the Resources Division achieved revenues of US$22.6 million (3.3 per cent. of Group revenues), operating profit of US$8.8 million (21.3 per cent. of Group operating profit) and net profits of US$12.0 million (33.1 per cent. of Group net profits). EBITDA for the period was US$15.7 million (28.9 per cent. of Group EBITDA). The following table sets out selected financial information of the Resources Division of Petrofac. It has been extracted or derived without material adjustment from, and should be read in conjunction with Part X Financial Information on Petrofac. H H (unaudited) US$ in thousands (unless stated otherwise) Total Revenue 22,572 21,569 45,042 14,439 13,914 Growth on prior period 4.7% 211.9% 3.8% Operating profit/(loss) 8,769 8,990 17,164 (1,805) 2,082 Net profits 12,034 3,552 6,953 1,579 2,396 EBITDA 15,730 16,354 32,289 2,572 2,716 Percentage Operating Margin 38.8% 41.7% 38.1% (12.5%) 15.0% Net Margin 53.3% 16.5% 15.4% 10.9% 17.2% EBITDA Margin 69.7% 75.8% 71.7% 17.8% 19.5% 94

95 H H (unaudited) US$ in thousands Investment expenditure 3,794 8,640 10,465 17,741 42,811 Book value (period end) 96, ,038 99, ,277 85, Resources 6 months ended 30 June 2005 compared with unaudited 6 months ended 30 June 2004 Revenues in H increased by 4.7 per cent. to US$22.6 million (H1 2004: US$21.6 million) reflecting an increase in the Division s share of revenue from the KPC joint venture offset by a reduction in the revenues arising from the Ohanet investment (H having benefited from revenue catch-up in accordance with the terms of the RSC arising from lower levels of production during start-up in late 2003). The Ohanet investment represented approximately 80 per cent of total revenue for the period (H1 2004: 86 per cent.). There were no new investments made in the period that contributed to revenue. Operating profit fell by 2.5 per cent. to US$8.8 million (H1 2004: US$9.0 million), representing a margin of 38.8 per cent. (H1 2004: 41.7 per cent.). The Ohanet investment represented approximately 95.2 per cent. of total operating profit for the period (H1 2004: 55.0 per cent.). The decline in operating margin as compared to H mainly reflects lower gains on the disposal of certain investments and a decline in depreciation and amortisation as a percentage of revenues. Net profits in H increased by per cent. to US$12.0 million (H1 2004: US$3.6 million), representing 53.3 per cent. of revenues (H1 2004: 16.5 per cent.). The increase in net profit is primarily attributable to a reduction in finance costs (due to the progressive repayment of project finance loans relating to the Ohanet investment) and the impact of an income tax credit of US$7.6 million arising from tax losses in Petrofac (Malaysia-PM304) Limited (the Division s investment in Cendor). These tax losses, due to uncertainty of utilisation, had not been previously recognised as an asset. Excluding the effects of this tax credit, net profit for H represented 19.6 per cent. of revenues. EBITDA was US$15.7 million (H1 2004: US$16.4 million), representing a margin of 69.7 per cent. (H1 2004: 75.8 per cent.). The decline in EBITDA margin as compared to H reflected the factors affecting the operating margin, as discussed above. Investment expenditure during the period amounted to US$3.8 million towards the Cendor and Ohanet investments (H1 2004: US$8.6 million). As at 30 June 2005, the book value of investments made by the Resources division was US$96.6 million (30 June 2004: US$106.0 million) Resources 2004 financial year compared with 2003 financial year Revenues increased to US$45.0 million (2003: US$14.4 million) reflecting a full year s contribution from the investment in the Ohanet development which commenced production in late October 2003, together with additional revenue in the year in accordance with the terms of the RSC, arising from lower production levels during start up in late The Ohanet investment represented 82.8 per cent. of total revenues for the year (2003: 24.1 per cent.). Operating profit increased to US$17.2 million (2003: operating loss US$1.8 million), representing a margin of 38.1 per cent. (2003: negative 12.5 per cent.) and reflecting a full year s contribution from Ohanet (2003: 2 months) included a write-down in value of the KPC investment. Depreciation and amortisation of US$15.1 million (2003: US$4.4 million) was charged reflecting principally the full year impact of the depreciation charge relating to the Ohanet investment. Net profits increased to US$7.0 million (2003: US$1.6 million), representing a margin of 15.4 per cent. (2003: 10.9 per cent.). The increase in net profit margin in 2004 as compared to 2003 reflects the full year contribution from the Ohanet investment, net of tax (2003: 2 months), partly offset by an increase in interest payable. Prior to commencement of production in late October 2003, interest costs relating to the Ohanet investment were capitalised. 95

96 EBITDA increased to US$32.3 million (2003: US$2.6 million), representing a margin of 71.7 per cent. (2003: 17.8 per cent.). The increase in EBITDA margin reflected the factors affecting the operating margin, as discussed above. Investment expenditure during 2004 amounted to US$10.5 million (2003: US$17.7 million) towards the Ohanet, Cendor and KPC investments. At the end of 2004, the book value of investments made by the Resources division was US$99.3 million (2003: US$106.3 million) Resources 2003 financial year compared with 2002 financial year Revenues increased to US$14.4 million (2002: US$13.9 million) comprising revenues arising from the initial production from the Ohanet development from late October 2003, partly offset by a fall in revenues from facilities management contracts in Fujairah (UAE) and Bolivia, which during the year came to an end. An operating loss of US$1.8 million was incurred in 2003 (2002: operating profit of US$2.1 million) primarily attributable to the impairment of KPC, together with the factors affecting revenues, as discussed above. Net profits decreased by 34.1 per cent. to US$1.6 million (2002: US$2.4 million), representing a margin of 10.9 per cent. (2002: 17.2 per cent.). A positive net margin position was achieved as a result of reflecting the minority interest share of losses of US$3.1 million in relation to the KPC investment, together with a small tax credit (US$0.2 million) arising from the Division s UK operation. EBITDA decreased marginally to US$2.6 million (2002: US$2.7 million), representing 17.8 per cent. of revenues (2002: 19.5 per cent.). The decrease in EBITDA margin reflected the factors affecting the operating margin, as discussed above. Investment expenditure during 2003 amounted to US$17.7 million (2002: US$42.8 million) towards the Ohanet investment. At the end of 2003, the book value of investments made by the Resources division was US$106.3 million (2002: US$85.4 million). 11. Discontinued operations The origins of Petrofac s US operations date back to 1981 when they were founded as a US based EPF business operating as both a domestic and an international EPF contractor, principally focused on the design and fabrication of modular plant for the upstream oil and gas and downstream refining markets. As the US business pursued growth and expansion of its EPF offering into EPC with the development of its own construction management capability certain lump sum contracts, in particular with respect to a major contract to construct FPSO modules for Petrobras, did not perform to expectation and the US operations generated losses. In early 2003, the Group concluded it should exit the US business, in part reflecting the highly competitive domestic market but also the uncertainty of achieving a satisfactory recovery from the ongoing underperformance within a reasonable timeframe. In April 2003, Petrofac sold the business for US$25.6 million. As part of that transaction, Petrofac was required to complete the contracts that remained in progress as at the date of sale. Cost-overruns on the Petrobras project continued to increase, principally due to delays in the project timetable as a consequence of difficulties with certain subcontractors and the need to undertake rework. The Petrobras modules were shipped in July 2004, at which time Petrofac s obligations under the underlying contract were substantially satisfied. As at 30 June 2004, the physical work under the contracts to be completed by Petrofac was substantially complete, subject to a number of relatively minor commercial issues, principally relating to ongoing legal disputes. 96

97 The following table sets out selected financial information for the discontinued operations of Petrofac. It has been extracted (with the exception of EBITDA) without material adjustment from, and should be read in conjunction with the Financial Information set out in Part X Financial Information on Petrofac. H H (unaudited) US$ in thousands Total Revenue 230 7,178 13,750 89,511 86,149 Operating loss (249) (12,958) (13,197) (10,804) (18,457) Net loss (202) (12,942) (13,162) (16,241) (12,268) EBITDA (249) (12,952) (13,184) (6,459) (17,511) 12. Liquidity and cash resources 12.1 Statement of cash flows The following table sets out the cash flow statements relating to Petrofac. It has been extracted without material adjustment from, and should be read in conjunction with, Part X Financial Information on Petrofac. H H (unaudited) US$ in thousands Operating activities Net profit before income taxes and minority interests: Continuing operations 37,684 29,977 62,736 37,774 36,216 Discontinued operation (202) (12,942) (13,162) (11,326) (18,428) 37,482 17,035 49,574 26,448 17,788 Adjustments for: Depreciation, amortisation and impairment 13,265 12,696 27,888 11,059 4,329 Finance costs, net 3,350 2,460 5, (949) Minority interests , Other non cash items, net 2, (412) (158) 958 Gain on disposal of discontinued operation (12,507) Gain on disposal of investments (1,819) (2,402) (2,932) Operating profit before working capital changes 54,676 29,921 79,676 28,501 22,440 Trade and other receivables (7,574) (26,635) (99,582) (8,247) (10,017) Work in progress (44,572) 11,308 (6,196) (55,725) (17,616) Due from related parties (10,601) (19,596) 2,840 Inventories 67 (249) (113) 1, Other current assets 13,765 (9,560) 171 4,002 (20,353) Trade and other payables (15,274) (16,375) (4,581) (5,610) 51,322 Billings in excess of cost and estimated earnings (56,233) 12,166 60,773 (21,476) (14,407) Accrued contract expenses and provisions 91,311 (11,509) 28,489 52,971 4,579 Due to related parties 73 (108) 1, (352) Accrued expenses and other liabilities 2,835 8,472 17,965 (2,791) 3,645 28,473 (2,275) 78,693 (26,781) 22,143 Other non-current items, net (622) 11,901 19,123 13,689 (11,782) 97

98 H H (unaudited) US$ in thousands Cash generated from/(used in) operations 27,851 9,626 97,816 (13,092) 10,361 Interest paid (5,296) (3,168) (5,695) (1,705) (1,169) Income taxes paid, net (7,548) (6,016) (13,278) (2,590) (777) Net cash flows from/(used in) operating activities 15, ,843 (17,387) 8,415 Of which discontinued operations (112) (9,589) (8,903) (35,927) (451) Net cash flows used in investing activities (6,627) (19,855) (27,243) (11,082) (65,127) Of which discontinued operations 1, ,929 (6,662) Net cash flows (used in)/from financing activities (16,177) (12,820) (19,153) 14,630 56,667 Of which discontinued operations 5,317 Net (decrease)/increase in cash and cash equivalents (7,797) (32,233) 32,447 (13,839) (45) Cash and cash equivalents at 1 January 127,823 95,376 95, , ,260 Cash and cash equivalents at period end 120,026 63, ,823 95, , Cash flows 6 months ended 30 June 2005 compared with unaudited 6 months ended 30 June 2004 Operating activities On continuing operations, net cash flow from operating activities was US$15.1 million (H1 2004: US$10.0 million), representing 27.8 per cent. of EBITDA (H1 2004: 22.2 per cent.). The increase in operating cash flow, compared with H1 2004, was attributable to the increase in operating profits, partly offset by a higher level of investment in working capital. Net cash flow used in the Group s discontinued operation was US$0.1 million (H1 2004: US$9.6 million). The net cash flow from all operating activities in H was US$15.0 million (H1 2004: cash flow US$0.4 million). Investing activities Net cash flows used in the Group s investing activities were US$6.6 million (H1 2004: US$19.9 million), including the following significant items: Capital expenditure on property, plant and equipment of US$6.3 million (H1 2004: US$9.1 million) in support of each of the Group s three trading divisions (H1 2004: principally E&C and Resources). Acquisitions during the period accounting for a US$4.1 million cash outflow (H1 2004: US$10.1 million), net of cash balances acquired relating to the acquisition of Rubicon Response (H1 2004: principally RGIT). Proceeds from the sale of available-for-sale investments and property, plant and equipment of US$5.2 million (H1 2004: US$0.4 million), including US$1.9 million relating to property, plant and equipment of the Group s discontinued operation (H1 2004: nil). 98

99 Financing activities Total net cash flows used in the Group s financing activities were US$16.2 million (H1 2004: US$12.8 million), including the following significant items: Proceeds from interest bearing loans and borrowings of US$20.3 million (H1 2004: nil), drawn from the Group s facility provided jointly by The Royal Bank of Scotland and Bank of Scotland. The proceeds were used in the acquisition of Rubicon Response, the exercise of the option to acquire Petrofac Ohanet (Jersey) Limited and the repayment of loan notes associated with the acquisition of RGIT, as well as general corporate purposes. Loan repayments of US$31.2 million (H1 2004: US$14.7 million), relating to full repayment of Ohanet non-recourse finance and the repayment of loan notes issued as part of the acquisition of RGIT. Dividends paid of US$6.6 million (H1 2004: US$1.3 million) Cash flows 2004 financial year compared with 2003 financial year Operating activities On continuing operations, net cash flow from operating activities was US$87.7 million (2003: US$18.5 million), representing 91.3 per cent. of EBITDA (2003: 38.6 per cent.) despite the growth in revenues. The increase in operating cash flow, compared with 2003, was attributable to the increase in operating profits together with a significantly lower level of investment in working capital. Working capital in 2003 increased by US$55.3 million largely as a result of the increased size of contracts undertaken by the E&C division. Although, the size of the contracts continued to rise in 2004, working capital requirements reduced, mainly due to the timing of milestone receipts on lump sum EPC contracts. Net cash flow used in the Group s discontinued operation was US$8.9 million (2003: US$35.9 million). The net cash flow from all operating activities in 2004 was US$78.8 million (2003: cash used US$17.4 million). Investing activities Net cash flows used in the Group s investing activities were US$27.2 million (2003: US$11.1 million), including the following significant items: Capital expenditure on property, plant and equipment of US$17.1 million (2003: US$34.3 million). The main elements of the expenditure in 2004 related to property, plant and equipment in support of the BTC/SCP project and the completion of capital works on the Group s investment in Ohanet. Acquisitions during the year accounting for a US$10.8 million cash outflow (2003: US$0.4 million), net of cash balances acquired. Of this amount US$9.1 million related to the acquisition of RGIT and US$1.0 million related to the acquisition of a 50 per cent. interest in Kyrgyz Petroleum Company and US$0.7 million related to additional payments associated with the acquisition of Chrysalis Learning. An investment of US$4.5 million (2003: nil) for a 30 per cent. interest in a PSC in Malaysia (the Cendor investment). Proceeds from the sale of available-for-sale investments and property, plant and equipment were US$3.1 million (2003: US$1.6 million). Financing activities Total net cash flows used in the Group s financing activities were US$19.2 million (2003 net cash flows from financing activities: US$14.6 million), including the following significant items: The repurchase of ordinary shares for a total consideration of US$30.8 million at the Company s internal market price (2003: US$8.3 million). The repurchase of shares in 2004 represented approximately 25 per cent. of the then issued share capital held by two retiring senior executives. 99

100 Proceeds from new bank facilities of US$45.7 million, net of debt acquisition costs, and the refinancing of existing term loans (2003: US$31.4 million). In 2004, the Group arranged a US$145 million facility, jointly provided by The Royal Bank of Scotland and Bank of Scotland to finance the share purchase referred to above and to refinance certain existing term loans and working capital facilities on more favourable commercial terms. Loan repayments of US$35.7 million (2003: US$2.3 million), primarily relating to Ohanet non-recourse finance and term loans assumed on the acquisition of RGIT. Proceeds of US$1.5 million (2003: nil) from the issue of share capital. Dividends paid of US$1.3 million (2003: nil) Cash flows 2003 financial year compared with 2002 financial year Operating activities On continuing operations, net cash flow from operating activities was US$18.5 million (2002: US$8.9 million), representing 38.6 per cent. of EBITDA (2002: 22.7 per cent.). The increase in operating cash flow, compared with 2002, was attributable mainly to the increased operating profits and a reduction in restricted cash balances. Notwithstanding these factors, working capital in 2003 increased by US$55.3 million (2002: US$0.3 million) largely as a result of the increased size of contracts undertaken by the E&C Division. Net cash flow used in the Group s discontinued operation was US$35.9 million (2002: US$0.5 million). The net cash flow used in all operating activities in 2003 was US$17.4 million (2002: cash flow from operations US$8.4 million). Investing activities Net cash flows used in the Group s investing activities were US$11.1 million (2002: US$65.1 million), including the following significant items: Capital expenditure on property, plant and equipment of US$34.3 million (2002: US$52.3 million). The main elements of the expenditure in 2003 related to the Group s investment in Ohanet and property, plant and equipment in support of the BTC/SCP contract (2002: principally Ohanet). Net cash from the sale of operating assets of the discontinued operation in April 2003 of US$20.7 million (2002: nil). Proceeds from the sale of property, plant and equipment and available-for-sale assets of US$1.6 million (2002: US$2.5 million). Acquisitions in the year of US$0.4 million, relating to Chrysalis Learning (2002: US$16.1 million: PGS PS). Financing activities Total net cash flows from the Group s financing activities were US$14.6 million (2002: US$56.7 million), including the following significant items: Proceeds from interest-bearing loans and borrowings, net of debt acquisition costs, of US$31.4 million (2002: US$88.5 million). The proceeds primarily related to a US$21.4 million term loan, denominated in Sterling, provided by The Royal Bank of Scotland and a drawdown of a project term loan utilised for the Ohanet project, (2002: Ohanet project funding and 3i variable rate unsecured loan notes). Loan repayments of US$2.3 million (2002: US$15.5 million), primarily relating to deferred consideration arising from acquisitions made by PGS PS prior to its ownership by Petrofac (2002: repayment of short-term funding for Ohanet). 100

101 The repurchase of ordinary shares from exiting US shareholders following the sale of Petrofac Inc. s operating assets in April 2003 for a total consideration of US$8.3 million (2002: nil). Redemption of the balance of outstanding preference shares issued as part of the Group reorganisation in 2002 for a total consideration of US$7.3 million (2002: US$0.3 million). In addition to the above factors, in 2002 US$16.3 million of cash was used in the corporate reorganisation in connection with, inter alia, the purchase of various minority interests (2003: nil) Restrictions on cash flow transfers from subsidiaries With the exception of Petrofac International Ltd (PIL), which undertakes the majority of Petrofac s lump sum EPC contracts and which, under its existing banking covenants, is restricted from making upstream cash payments in excess of 70 per cent. of its net income in any one year, none of the Company s subsidiaries is subject to any material restrictions on their ability to transfer funds in the form of cash dividends, loans or advances to the Company. The restriction on PIL has been taken into account in the Company s working capital statement set out in paragraph 16 below Working capital and capital expenditure requirements Working capital requirements The majority of the Group s revenue and working capital requirements are derived from a relatively small number of contracts within the E&C and OS Divisions. The working capital requirement of the Resources Division is, by comparison, small. The Company s opinion on the availability of sufficient working capital is set out in paragraph 16 below. E&C Division The E&C Division s EPC contracts are typically undertaken on a fixed price or lump sum basis, frequently extending beyond a single financial year end and often beyond two years. The timing of cash flow realised during the course of a lump sum EPC contract does not necessarily closely follow the recognition of profit. This may be due to the receipt of advance payments from the client ahead of contract mobilisation, potentially significant cash outflows arising from procurement of major equipment and materials and also to the nature and timing of contractually determined milestone payments. The E&C Division, in respect of lump sum contracts, typically operates with a negative working capital requirement, as significant customer prepayments are a feature of these contract activities. The E&C Division s engineering service and consultancy contracts are typically undertaken on a reimbursable basis against an agreed schedule of rates, plus, in certain circumstances, incentive payments arising out of the performance according to specified KPIs. The timing of cash flow realised by the engineering service and consultancy business is less volatile than lump sum EPC contracts as a result of a smaller and more diversified contract base. As a result, the working capital requirements are more predictable although they do, however, vary across the geographical areas in which the business operates and typically are higher for international contracts. OS Division The OS Division s contracts are typically undertaken on a reimbursable basis against an agreed contract schedule of rates, plus, in certain circumstances, incentive payments arising out of the performance according to specified KPIs. The OS Division s working capital requirements vary by client and geographical area reflecting varying credit terms, which can range from neutral funding to, typically, 30 days, dependent on the nature of service provided and the client. Typically, working capital requirements are higher for international contracts as compared with UKCS contracts. Resources Division In the Resources Division, each investment has its own individual working capital profile. The working capital requirement of the Division s principal investment, Ohanet, is relatively low with typically no more than one month s receivable outstanding at any point in time. The Division s joint venture interest in KPC also has a low working capital requirement as all sales are conducted on a pro forma basis, that is, receipt of payment on delivery of product. 101

102 Capital expenditure The following table shows the capital expenditures (before consolidation and elimination adjustments) for tangible and intangible fixed assets of the continuing operations within the Petrofac Group on the dates indicated. The information has been extracted without material adjustment from note 3 to Part X Financial Information on Petrofac. 6 months ended 30 June 2005 Year ended 2004 Year ended 2003 Year ended 2002 US$ in millions E&C OS Resources Total E&C Division Typically, the E&C Division has limited capital expenditure requirements. The increases in capital expenditure seen in financial years 2003 and 2004 relate principally to the Group s proportionate share of the investment made by the joint venture vehicle, Spie Capag Petrofac International Limited in plant and equipment in connection with the BTC/SCP project. OS Division The capital expenditure of the OS Division has typically been limited to the purchase of computer equipment, leasehold improvements and, since the acquisition of RGIT in 2004, additions to plant and equipment within Petrofac s training facilities. Resources Division The Resources Division, by the nature of its activities, has the most significant capital requirements within the Group. Since 2002, the Resources Division s capital expenditure has principally comprised its investment in the Ohanet project, which began operations in October In 2004 and H however, the division has also incurred capital expenditure relating to its oil and gas interests in Malaysia and the UK. At 30 June 2005, the Group had capital commitments of US$0.1 million ( 2004: nil), all of which related to the Resources Division. 13. Ratio analysis The following tables set out a summary of interest cover, relating to the continuing operations of Petrofac, and debt/equity ratios relating to Petrofac. The data used in the ratio calculations has been extracted without material adjustment from, and should be read in conjunction with, Part X Financial Information on Petrofac Interest cover ratio months ended 30 June 2005 Year ended 2004 Year ended 2003 Year ended 2002 US$ in thousands (unless stated otherwise) Operating profit from continuing operations (A) 41,081 68,283 37,747 35,296 Interest costs/(income), net (B) 3,397 5,547 (27) (920) Interest cover (A/B) 12.1 times 12.3 times Net interest Net interest receivable receivable

103 In the 2002 and 2003 financial years, the Group had net interest receivable. In the financial year 2004, the Group had net interest payable reflecting: a full year of interest on project finance for the Ohanet investment which was being capitalised in the period before project completion; interest cost on assumed loans and borrowings following the acquisition of RGIT and incurred in conjunction with the buy back in October 2004 of approximately 25 per cent. of the Company s then issued share capital; and an increase in interest rates in the UK and US. Notwithstanding this increase in net interest payable, net interest cover was 12.3 times in the year. In H1 2005, the ratio of interest cover has been broadly maintained Debt/equity ratio 30 June 2005 (adjusted) 30 June US$ in thousands Interest-bearing loans and borrowings (A) 117, , , ,593 87,116 Cash and short term deposits (B) 141, , ,534 97, ,524 Net debt/(cash) (C = A B) (24,059) 13,598 17,944 20,091 (23,408) Total net assets (D) 171, , , ,394 96,102 Gross gearing ratio (A/D) 68.4% 115.8% 116.5% 107.5% 90.6% Net gearing ratio (C/D) Net cash position 10.2% 13.0% 18.4% Net cash position At 30 June 2005, interest-bearing loans and borrowings include US$37.7 million relating to 3i s holding of A ordinary shares, which as a result of a right to a fixed 5 per cent. dividend, have been classified as a current debt instrument. Immediately prior to Admission, the A ordinary shares held by 3i will be converted to Ordinary Shares and consequently will be reclassified as equity, thereby significantly reducing the gearing ratio of the Group. The adjusted 30 June 2005 figures above reflect the effects of this reclassification to equity. Details of the conversion are set out in note 22 and 23 to Part X Financial Information on Petrofac. 103

104 14. Capitalisation and indebtedness 14.1 Capitalisation and gross indebtedness The following table sets out the gross indebtedness of the Group as at 15 August 2005 and 30 June 2005, the Group committed borrowing facilities available as at 15 August 2005 and the capitalisation of the Group as at 30 June Group borrowings and borrowing facilities denominated in currencies other than US$ have been translated at prevailing exchange rates on 15 August Group committed borrowing facilities Indebtedness as at 30 June 2005 Indebtedness as at 15 August 2005 available as at 15 August 2005 US$ in thousands Current debt instruments Revolving credit facility 3,250 3,250 3,270 Bank overdrafts general use 21,401 17,702 33,589 Bank overdrafts project specific ,891 Project term loan 7,000 7,000 7,000 Non-current debt instruments Revolving credit facilities 13,203 13,241 40,000 Term loan 73,569 73,902 73,902 Total current and non-current debt instruments 118, , ,652 Contingent indebtedness Letters of credit 19,318 13,113 82,423 Letters of guarantee (including performance and bid bonds) 334, , ,421 Forward exchange contracts (1) 104,344 94, ,781 Total current and non-current debt instruments and contingent liabilities 576, , ,277 A ordinary shares (2) 37,657 37,657 Total gross indebtedness (3) 614, ,138 Capitalisation as at 30 June 2005 US$ in thousands Shareholders equity Share capital 7,184 Share premium reserve 29,219 Capital redemption reserve 10,881 Total capitalisation (4) 47,284 Notes: (1) Amounts reported represent the net value of forward currency contracts based on notional facility amounts. The gross value of forward contracts entered into by the Group was US$255.7 million at 15 August 2005 with committed facilities of US$607.5 million as at that date. (2) Immediately prior to Admission, the A ordinary shares will be converted to ordinary shares and consequently will be reclassified as equity, without a cash outflow. (3) Total gross indebtedness excludes US$1.3 million interest payable at 15 August 2005 on the above borrowings. (4) Shareholders equity as stated above excludes retained earnings reserve, foreign currency translation reserve and reserves attributable to net unrealised gains and losses on available-for-sale financial assets and derivatives which, in aggregate, totalled US$86.6 million at 30 June There has been no material movement in the Company s capitalisation, as set out in the above table, between 30 June 2005 and 15 August

105 As at 15 August 2005, the Group had committed borrowing facilities of, in aggregate, US$847.3 million of which US$198.7 million related to current and non-current debt instruments and the balance related to facilities available for the provision of letters of credit, letters of guarantee (including performance and bid bonds) and forward exchange contracts. Such contingent liabilities typically arise in connection with the Group s EPC activities. As at the same date, the Group s total gross indebtedness was, in aggregate, US$530.5 million (excluding US$37.7 million of A ordinary shares which, immediately prior to Admission, will be converted into ordinary shares and consequently classified as equity), which comprised US$115.5 million related to current and non-current debt instruments and US$415.0 million related to contingent liabilities. A further analysis of the Group s indebtedness as at 15 August 2005 is provided below, distinguishing between guaranteed, secured and unguaranteed/unsecured indebtedness: Indebtedness as at 15 August 2005 Notes US$ in thosuands Total current debt Guaranteed (1) 24,702 Secured (2) 3,685 Unguaranteed/Unsecured 37,657 66,044 Total non-current debt (including contingent indebtedness) Guaranteed (1) 108,461 Secured (3) 393,633 Unguaranteed/Unsecured 568,138 (1) Guaranteed by the Company, supported by additional guarantees from certain subsidiary companies. (2) Secured against project receivables. This indebtedness is also guaranteed by the Company. (3) Secured against project receivables and by cash pledges. Of the total non-current secured indebtedness, US$341.6 million is also guaranteed by the Company Net indebtedness The Group s current and non-current net financial indebtedness, as at 15 August 2005, was: US$ in thousands A Cash 125,239 B Cash equivalents 99,725 C Trading securities 681 D Liquidity (ABC) 225,645 E Current bank debt (21,387) F Current portion of non-current debt (7,000) G Other current financial debt (37,657) H Current financial debt (EFG) (66,044) I Net current cash/(financial indebtedness) (HD) 159,601 J Non-current debt (87,143) K Net cash/(financial indebtedness) before contingent indebtedness (IJ) 72,458 L Contingent indebtedness including bonds issued and forward exchange contracts (414,951) M Non current financial indebtedness (JL) (502,094) N Net financial indebtedness (IM) (342,493) Group cash and borrowings denominated in currencies other than US$ have been translated at prevailing exchange rates on 15 August

106 As set out above, as at 15 August 2005, the Group had net cash (before taking into account contingent liabilities) of US$72.5 million, comprising cash, cash equivalents and trading securities of US$225.6 million, and total current and non-current financial debt of US$153.2 million, of which US$37.7 million related to the A ordinary shares which, upon Admission, will not be classified as debt. In addition, as at 15 August 2005, the Group had total contingent indebtedness of US$415.0 million. As at 15 August 2005, the Group did not have any indirect indebtedness, whereby the indebtedness of a third party outside the Group may, whether through guarantee obligations or some other form of contractual obligation, become the legal indebtedness of the Group Maturity profile of borrowings and undrawn committed borrowing facilities The following table sets out the maturity profile of the Group s borrowings and undrawn committed borrowing facilities as at 15 August year 1-5 years 5 years Total US$ in thousands Borrowings Revolving credit facilities 3,250 9,365 3,876 16,491 Bank overdrafts general usage 17,702 17,702 Bank overdrafts project specific Term loans 48,125 25,777 73,902 Project term loan 7,000 7,000 A ordinary shares 37,657 37,657 66,044 57,490 29, ,187 Undrawn committed borrowing facilities Revolving credit facilities 20 19,135 7,624 26,779 Bank overdrafts general usage 15,887 15,887 Bank overdrafts project specific 40,456 40,456 56,363 19,135 7,624 83,122 The maturity profile of borrowings includes US$37.7 million of A ordinary shares, which as a result of rights to a fixed 5 per cent. dividend, are classified as a current debt instrument. Immediately prior to Admission, the A ordinary shares will be converted to ordinary shares and consequently will be reclassified as equity, without a cash outflow. Excluding the A ordinary shares, the Group has a balanced borrowing profile with 25 per cent. of borrowings maturing within one year, 49 per cent. maturing between one and five years and the remaining 26 per cent. maturing in more than five years. Of the borrowings maturing within one year, excluding the A ordinary shares, US$21.4 million relates to revolving credit facilities and bank overdrafts all of which are subject to annual renewal. Group borrowings, including working capital requirements, are typically not seasonal but are influenced by the needs of individual contracts for the E&C and OS divisions and investment requirements for the Resources division. 15. Treasury management 15.1 Funding and non-funding requirements The Group currently satisfies its funding requirement from the cash generated within its business and through the use of external debt. The Group s funded borrowing requirements are principally financed through a facility provided by The Royal Bank of Scotland and Bank of Scotland. See paragraph 14.1 of Part IX Additional Information for a summary of the terms of this facility. The Group s non-funded requirements, which mainly comprise letters of credit and performance guarantees, and which are predominantly required for the Group s international activities are sourced from a number of international and regional banks Cash and cash equivalents The Group prepares its financial statements in US$, as a significant proportion of the Group s assets, liabilities, income and expenses are US$ denominated. Notwithstanding this, the Group 106

107 manages its cash resources in a number of currencies besides US$. Typically, cash resources are held in currencies other than US$ when either the functional currency of individual subsidiaries are non-us$ or when the Group has an anticipated future commitment in a currency other than US$. The table below sets out the currency composition of cash and cash equivalents held at 15 August Percentage of total US$ in thousands US$ ,600 Euros ,950 Sterling 3.8 8,616 Kuwaiti Dinars ,761 Others ,037 Total , Management of exchange rate exposure Engineering & Construction A significant proportion of the E&C Division s assets, liabilities, income and expenses are US$ denominated. Lump sum EPC contracts are almost always required to be priced in US$. Depending on the procurement strategy, in particular its scale, timing and vendors business currency for purchasing the equipment and materials, there may be a significant non-us$ exposure and risk to the budgeted profitability should the non-us$ currency appreciate against the US$ before the purchasing is complete. Typically, the E&C Division will seek to mitigate this exchange rate risk upon each contract award by purchasing forward an appropriate amount of the non-us$ currency. The E&C Division s engineering and consulting business, located in Woking, England, undertakes work on an international basis, with its income typically denominated in either US$ or Euros. Its costs are predominantly Sterling based. Typically, the business will seek to mitigate this exchange rate risk and protect its budgeted margin on a contract by contract basis by selling forward an appropriate amount of the appropriate currencies to match its Sterling costs. Operations Services A significant proportion of the OS Division s assets, liabilities, income and expenses are Sterling denominated reflecting the scale of the business undertaken within the UKCS. The OS Division s international activities are typically US$ denominated and the assets, liabilities, income and expenses relating thereto are also US$ denominated. Only in very limited circumstances is there a requirement to mitigate exchange rate exposure. Where this does arise, the OS Division will seek to mitigate this risk through appropriate provisions within the contract with the client. Resources Most of the world s oil and gas investment projects are denominated in US$. The Resources Division s activities are therefore predominantly US$ denominated. Details of the foreign currency hedge instruments used by the Group are set out in note 31 to Part X Financial Information on Petrofac 15.4 Management of interest rate risk Interest rate risk arises from the possibility that changes in interest rates will affect the value of the Group s interest-bearing financial liabilities and assets. The Group s exposure to market risk for changes in interest rates relates primarily to the Group s long term variable rate debt obligations and its cash and bank balances. In 2004, the Group established a formal policy to manage its interest cost using a mix of fixed and variable rate debt and specifically to keep between 60 per cent. and 80 per cent. of its borrowings at fixed rates of interest. The Group has used simple hedge instruments to achieve this objective. Details of the instruments used by the Group are set out in note 31 to Part X Financial Information on Petrofac. 107

108 16. Working capital The Company is of the opinion that, taking into consideration the bank and other facilities available to the Group, the working capital available to the Group is sufficient for its present requirements, that is, for at least the 12 months from the date of publication of this document. 17. Current trading and prospects 17.1 Engineering & Construction The Directors believe revenue backlog and the composition of projects within backlog to be an important performance indicator for the E&C business. As at 30 June 2005, the revenue backlog for the E&C Division had increased by 40.9 per cent., to US$1,041 million, compared to 2004, driven by several new contract wins, principally the KOC Upgrade EPC contract, and resulting in a higher composition of early phase work in H versus previous periods. Since 30 June 2005, Petrofac was awarded a US$246 million EPC contract with the Sultanate of Oman in July 2005 to construct a new gas plant in the Kauther field in Oman. Notwithstanding this increase in backlog, the Directors expect a relatively moderate level of revenue growth from the E&C Division between the first and second half of the year, as certain contracts such as the QP and Crescent contracts will be reaching substantial completion during H2 2005, while various other projects in backlog will still be in early phase. Petrofac does not recognise profits on lump sum contracts until it has reached a threshold percentage of completion. Therefore, a higher concentration of early stage projects in the E&C revenue backlog will tend to reduce operating margins and, as such, the Directors believe that operating margins for H may be moderately lower than for H During 2006, as the existing projects in the backlog, including the KOC Upgrade EPC contract and the Kauther gas plant EPC contract contract, reach a more advanced stage, in the absence of unforeseen circumstances and subject to the scale and timing of further contract awards, this should have a positive effect on margins as compared to H Over the medium term, the Directors expect revenue growth within its E&C Division to be constrained more by its internal resource capacity than by business opportunities, and anticipate that revenue growth will moderate Operations Services The Directors believe revenue backlog and the composition of projects within backlog to be an important performance indicator for the OS business. As at 30 June 2005, the revenue backlog for the OS Division had increased by 45.2 per cent., to US$1,453 million, compared to 2004, considerably improving the long-term outlook for the division. During H1 2005, the Lundin service operator, Total operations and maintenance, and KOC maintenance management contracts commenced which should all make a full year impact in However, given that the majority of the OS Division s contracts are Sterling based (and costed), the recent strengthening of the US Dollar against Sterling during H may, to the extent that it is sustained, have a negative impact on revenue and profit growth for that period as compared to H The Directors believe that, because of the nature of the services provided, the UKCS facilities management and service operator contracts of the OS Division can be expected to have a lower variability of operating margins than the E&C contracts over the life of a contract Resources Over the next 12 months the Ohanet investment is expected to continue to be the largest investment in Resources portfolio. Given the nature of the Ohanet RSC (see the description of the Ohanet project in Section 4 of Part III Information on the Petrofac Group ), the Directors expect this investment to provide relatively stable revenues and cash flows. During the 6 months ended 30 June 2005, the Resources Division benefited from an exceptional US$7.6 million tax credit associated with its investment in the Cendor asset. The Directors expect Cendor to commence production in late 2006, which is expected to result in increased revenues and profitability for the division in accordance with the terms of the PSC. 108

109 PART VII Competent person s report by Ryder Scott [Please see over] 109

110 1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS TELEPHONE (713) FAX (713) September 21, 2005 Petrofac Limited Whiteley Chambers, Don Street St. Helier, Jersey JE4 9WG United Kingdom Credit Suisse First Boston (Europe) Limited 1 Cabot Square London E14 4QJ United Kingdom Lehman Brothers International (Europe) Lehman Brothers Europe Limited 25 Bank Street London E14 5LE United Kingdom Gentlemen: At your request, we have prepared an estimate of the future net reserves and income attributable to certain leasehold interests of subsidiaries of Petrofac Limited (Petrofac) as of June 30, The subject properties are located in Algeria and offshore Malaysia. The income data were estimated utilizing economic parameters supplied by Petrofac. At the request of Petrofac, only its Algerian and Malaysian fields were evaluated in this report, because in its view, at present these are the two upstream assets which are material to Petrofac. As a result of both economic and political forces, there is significant uncertainty regarding the forecasting of future hydrocarbon prices. The recoverable reserves and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below. PETROFAC ECONOMIC PARAMETERS Estimated Net Reserve and Income Data Certain Leasehold Interests of Subsidiaries of Petrofac Limited Algerian and Malaysian Upstream Assets As of June 30, 2005 Net Reserves Future Net Income (US$000) Category Oil (MBBL) Undiscounted Proved 7,384.0 $ 213,086 $ 157,121 Probable 1,696.8 $ 5,436 $ 2,175 Proved + Probable 9,080.8 $ 218,522 $ 159,296

111 Petrofac Limited September 21, 2005 Page 2 The values shown in the previous table are inclusive of the financial remuneration received by Petrofac for the Ohanet Field for which no reserve volumes are attributable to Petrofac as per the terms of the RSC. The future undiscounted and discounted future net income at 10 percent for the Ohanet Field comprise approximately 70 percent and 72 percent respectively of the corporate total for the Algerian and Malaysian assets included within this report. PETROFAC ECONOMIC PARAMETERS Estimated Net Income Data Certain Petrofac Limited Leasehold Interests in the Risk Service Contract (RSC) Ohanet Field, Algeria As of June 30, 2005 Net Reserves Future Net Income (US$000) Category Oil (MBBL) Undiscounted Proved - $ 153,252 $ 114,885 Probable Proved + Probable - $ 153,252 $ 114,885 Petrofac s share of the Contractor s Risk Service Contract (RSC) with Sonatrach in relation to the Ohanet Field provides only for financial remuneration resulting from future field operations, such remuneration being paid in kind, and does not convey actual proportionate ownership of produced hydrocarbon volumes. As part of our due diligence as required for the preparation of this report, we have confirmed that the reserve volumes associated with the financial remuneration to Petrofac for the Ohanet RSC are equal to or in excess of the volumes required for fulfillment of the RSC contractual terms. PETROFAC ECONOMIC PARAMETERS Estimated Net Reserve and Income Data Certain Petrofac Leasehold Interests in the Cendor Field, Offshore Malaysia As of June 30, 2005 Net Reserves Future Net Income (US$000) Category Oil (MBBL) Undiscounted Proved 7,384.0 $ 59,834 $ 42,236 Probable 1, ,436 2,175 Proved + Probable 9,080.8 $ 65,270 $ 44,411 Liquid hydrocarbons are expressed in standard 42 gallon barrels. The future net income reflects certain deductions from liquid hydrocarbons revenue. The deductions are comprised of the normal direct costs of operating the wells, costs of personnel, royalty and taxes. The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded annually. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

112 Petrofac Limited September 21, 2005 Page 3 The following table summarizes the total future net income at various discount rates. Subsidiaries of Petrofac Limited Total Algerian and Malaysian Upstream Assets Discounted Future Net Income, US$000 As of June 30, 2005 Discount Rate Total Total Total Percent Proved Probable Proved+ Probable 0 $ 213,086.0 $ 5,436.0 $ 218, $ 166,197.0 $ 2,592.0 $ 168, $ 157,121.0 $ 2,175.0 $ 159, $ 148,859.0 $ 1,831.0 $ 150,690.0 Subsidiaries of Petrofac Limited Ohanet Field, Algeria Discounted Future Net Income, US$000 As of June 30, 2005 Discount Rate Total Total Total Percent Proved Probable Proved+ Probable 0 $ 153, $ 153, $ 121, $ 121, $ 114, $ 114, $ 109, $ 109,185.0 Subsidiaries of Petrofac Limited Cendor Field, Offshore Malaysia Discounted Future Net Income, US$000 As of June 30, 2005 Discount Rate Total Total Total Percent Proved Probable Proved+ Probable 0 $ 59,834.0 $ 5,436.0 $ 65, $ 45,061.0 $ 2,592.0 $ 47, $ 42,236.0 $ 2,175.0 $ 44, $ 39,674.0 $ 1,831.0 $ 41,505.0 The results shown above are presented for your information and should not be construed as our estimate of fair market value. Reserves Included in This Report The petroleum reserves included in this report are classified by degrees of proof as proved or probable. Definitions of proved and probable reserve classifications utilized in this report are in accordance with the reserve definitions presented in Appendix 1 of the Listing Rules of the UK Listing Authority (and also contained in Part XII Glossary of Industry Terms ). Such definitions are not materially different from those customarily utilized in the United States (i.e. the SEC definitions of proved reserves and SPE/WPC definitions for probable reserves). The petroleum reserves are classified as follows: RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

113 Petrofac Limited September 21, 2005 Page 4 Proven Reserves mean, in respect of mineral companies primarily involved in the extraction of oil and gas resources, those reserves which on the available evidence and taking into account technical and economic factors have a better than 90% chance of being produced. Probable Reserves mean, in respect of mineral companies primarily involved in the extraction of oil and gas resources, those reserves which are not yet proved but which on the available evidence and taking into account technical and economic factors have a better than 50% chance of being produced. For the purposes of these definitions, present producing methods are limited to primary depletion or secondary recovery by water or gas injection and do not include enhanced petroleum recovery techniques. The extent to which probable reserves ultimately may be reclassified as proved reserves is dependent upon future drilling, testing and well performance. The degree of risk to be applied in evaluating probable reserves is influenced by economic and technological factors as well as the time element. Probable reserves in this report have not been adjusted in consideration of these additional risks and therefore are not comparable to the proved reserves. Estimation of reserves is done under conditions of uncertainty. For this report, deterministic estimates of reserves have been prepared. The method of reserve estimation is called deterministic if a single best estimate of reserves is made based on known geological, engineering, and economic data. Identifying reserves as proved and probable has been the most frequent classification method and gives an indication of the probability of recovery. Because of potential differences in uncertainty, caution should be exercised when aggregating estimates of reserves of different classifications. Properties Included in the Evaluation Petrofac owns an interest in two principal upstream assets comprised of the Ohanet Field located in Algeria and the Cendor Field located offshore Malaysia. At the request of Petrofac, only its Algerian and Malaysian fields were evaluated in this report, because in its view, at present these are the two upstream assets which are material to Petrofac. Ohanet Field, Algeria (or People s Democratic Republic of Algeria) The Ohanet Field is located in the lllizi province, Algeria, approximately 1,300 km south east of Algiers and 100 km west of the country s border with Libya. The field is being developed under a Risk Service Contract (RSC) by a joint venture comprised of: BHP Billiton (45% and Operator) Japan Ohanet Oil & Gas Co (30%) Woodside Petroleum (15%) Petrofac Resources (10%) The above companies are known collectively as the Contractor within the RSC agreement with Sonatrach, the national oil company of Algeria. Petrofac acquired its 10% working interest in this project via its Algerian RSC executed with Sonatrach in July, RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

114 Petrofac Limited September 21, 2005 Page 5 Petrofac s share of the Contractor s RSC provides for financial remuneration resulting from future field operations, such remuneration being paid in kind, and does not convey actual ownership of a proportionate share of future produced hydrocarbon liquids. Under the terms of the RSC, Sonatrach retains ownership of all produced hydrocarbons until custody transfer occurs to the Contractors at the Algerian border. At custody transfer, the Contractors receive financial remuneration for operations under the RSC by means of beneficiary sales of the liquid hydrocarbon volumes equivalent to the preestablished remuneration amounts. As a consequence and at the request of Petrofac, this report therefore includes only those future cashflow streams resulting from Petrofac s net share of the RSC remuneration. As part of our due diligence as required for the preparation of this report, we have confirmed that the reserve volumes associated with the financial remuneration to Petrofac for the Ohanet RSC are equal to or in excess of the volumes required for fulfillment of the RSC contractual terms. Based upon our review of information provided by Petrofac regarding the terms of the RSC, Petrofac's ability to achieve its return as defined in the RSC is not materially impacted by variations in future hydrocarbon prices. The Ohanet Field was discovered during the late 1950 s to early 1960 s with 4 reservoirs ultimately being discovered. The reservoirs include wet gas reservoirs and a black oil reservoir with a large associated gas cap. The reservoirs have been delineated by more than 65 wells. The four reservoirs comprising the Ohanet Field include the following: Ohanet Devonian Dimeta West In Adaoui Ohanet Ordovician The only production prior to October, 2003 consisted of production from the oil rim of the Ohanet Devonian reservoir. Sonotrach entered into the RSC with the Contractor to redevelop the field including the implementation of a gas plant system which allows for the production and sale of plant liquids from each of the four reservoirs. The project s implementation consists of drilling up to 32 additional production wells, recompletion of 15 existing wells, building new facilities to handle up to 20 million standard cubic metres per day (mmcm/d) or 700 million cubic feet per day (MMCFD) of gas and 56,000 barrels of oil equivalent per day (BOEPD) for export via the existing Sonatrach infrastructure. Sonatrach retains rights to all processed gas volumes and as per the terms of the RSC allocates a portion of the associated production of plant liquids as remuneration for the capital and operating expenditures incurred by the Contractor during project implantation and operation. The general economic terms for the RSC are as follows: In addition to repayment of the investment, the RSC provides for an additional remuneration payable to the Contractor which is based upon a defined return, plus re-imbursement of agreed-upon reimbursable operating costs. Remuneration is made in kind as liquids (LPG s and condensate) delivered by Sonatrach to the Contractor at a loading port. The repayment of the operating cost share, the investment and the remuneration are designed to be repaid (with liquids) over a target period of eight years. If, however, insufficient liquids are produced to allow for the repayment within the 8 year period, an additional three year period is permitted to allow complete repayment. However, if, over the extended 11 year period, the average oil price is below a minimum threshold, an additional year will be granted to allow recovery. Thus, the contract could extend to a total of 12 years under certain scenarios. RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

115 Petrofac Limited September 21, 2005 Page 6 By Algerian law, the Contractor s annual revenue is capped to 49% of the total production of the field on a barrel of oil equivalent basis, inclusive of gas production. The Contractor funds all of the field development costs, currently forecast to be $1,065 million a minority of which is not recoverable. Development of the project commenced in September, 2000 with first gas and condensate production commencing in October, The run in test required delivery and processing of a contractually specified volume to the Sonatrach export pipelines which was successfully achieved by the Contractor in early The drive mechanism for each of the four reservoirs is expected to be pressure depletion. Based upon our review, the operator and Petrofac have prepared a detailed and very high quality analysis of these reservoirs in an attempt to optimize the ultimate recoveries from each reservoir. In our professional opinion, the operating consortium exhibits sufficient competency to produce the reserve volumes required for fulfillment of the terms of the RSC. Maps showing the geographical location of this field are shown in Attachments 1A and 1B. The contractual concession limit for the RSC license under the terms of the current agreement for Petrofac in the Ohanet RSC is 12 years maximum. It should be noted that the proved and probable reserves included within this evaluation are comprised of only those reserves, which can be produced within the 12-year period as stipulated by the current agreements for each field. Additional reserves may be recovered should the license terms be extended beyond those time limits assumed within this evaluation. Ohanet Devonian Reservoir The Ohanet Devonian field was discovered in Oil production commenced in the early 1960's in the wells drilled in the oil rim plus minor gas production from the wells penetrating the field's significant gas cap. The oil wells were converted to gas producers in order to facilitate implementation of the project. Ohanet Dimeta West Reservoir Dimeta West reservoir was discovered in 1970 as a gas condensate reservoir and was delineated by 9 wells. The field had never been produced prior to October, In Adaoui Reservoir The In Adaoui reservoir was discovered in This reservoir is a small gas condensate reservoir which had never been produced prior to October, Ohanet Ordovician Field The Ohanet Ordovician gas condensate reservoir was discovered in 1961 and subsequently appraised by eight wells. There has been little or no production prior to October, RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

116 Petrofac Limited September 21, 2005 Page 7 The reserve verifications prepared as part of our due diligence for the Ohanet Ordovician and Devonian reservoirs were based upon an audit of detailed reservoir simulations and a material balance analysis. Description of the Ohanet development The Development comprises all major fluid handling systems, including a two train 710 mmscf/d gas treatment facility (the Central Processing Facility ) fed by 47 production wells of which 32 will be new and 15 are re completions of existing oil wells. The CPF is fed by a gas gathering system comprising more than 150 kilometres of flowlines that connect the 47 wells. A total of 28 wells have been drilled and completed to date. The last four wells have been deferred to allow three to four years or production history to be gathered. Three of the new wells were drilled as horizontal underbalanced wells. The Ohanet structure is 42 kilometres long and 8 kilometres wide at its greatest extent. Included in the development are four separate hydrocarbon reservoirs, originally discovered in the late 1950s and early 1960s. Since then, they have been appraised and delineated by more than 65 wells. Three of the reservoirs are Devonian, lying at depths of between 7500 and 8880 feet. The fourth is Ordovician at approximately 9020 ft. Ohanet is the seventh wet gas development in the area south east of the Hassi R Mel complex in Algeria. Cendor Field, Offshore Malaysia The Cendor Field is located in the NE corner of Block PM304 in the South China Sea east of the Malaysian peninsula. The block covers an area of 682 km 2 and lies in water depths of up to 70 meters. This field is to be operated by Petrofac. The nearest infrastructures include the Floating Storage and Offloading Facility (FSO) of the Dulang oil field in the north, the Resak gas facilities in the adjacent northwest and the Tapis oil facilities in the east. Both the Resak gas pipeline and the Tapis oil pipeline run across the block to the onshore facilities in Kertih. A phased approach will be used to develop the Cendor Field. Phase 1 of the development program will be comprised of four producing wells and three injector wells. Production will be from an unmanned platform and these early wells will be utilized to assess reservoir performance for possible subsequent re-development of the field in Phase 2. The Cendor Field was acquired initially by Amerada Hess in February, 1998 as a split with Petronas Carigali under the revenue over cost (R/C) PSC terms. Petrofac acquired its interest from Amerada Hess in May, The current partners in the Cendor Field include the following: Company Working Interest, % Petrofac (Operator) 30 Petronas Carigali 30 KUFPEC 25 PIDC 15 The main reservoirs for the Cendor Field are the H15 and H20 reservoirs which are moderately high permeability, oil bearing reservoirs. Should the performance of the H15 and H20 reservoirs justify RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

117 Petrofac Limited September 21, 2005 Page 8 further development, a second set of wells will be drilled. The production from the second stage would be handled by a dedicated Central Processing Platform (CPP) to be located at Cendor. For purposes of this CPR, only the initial phase of development activity involving the first set of 4 producing wells and 3 injector wells has been utilized. Based upon this phased approach to development, a project producing life of only 12 years has been utilized for this analysis. The field is projected to commence production in Maps showing the geographical location of this field are shown in Attachments 2A and 2B. A typical structure map for the field is included as Attachment No. 3. General reservoir parameters for the Cendor Field are shown in the following table: CENDOR FIELD-RESERVOIR PARAMETERS H-15 H-20 Porosity, %: min Porosity, %: max Sw, %: min Sw, %: max Permeability, md: min 1 1 Permeability, md: max 1, ,180.0 Total Net Pay, ft: min Total Net Pay, ft: max Formation Temperature, o F Depth, ft 4,090 4,285 Formation Pressure, psi 2,220 2,245 Geopressure Gradient, psi/ft Based upon our review, Petrofac has prepared a detailed and high quality analysis of these reservoirs in an attempt to optimize the ultimate recoveries from each reservoir and exhibits sufficient technical and operational competency to produce the reserves included herein. Description of H-15 and H-20 Reservoirs and Discussion of Reserves. The H-15 and H-20 reservoirs are Oligocene aged reservoirs. The early opening of the NW-SE trending Malay Basin was extensional and produced localized grabens. These early grabens were rapidly in-filled. By the Late Oligocene regional tectonic movements resulted in the full expansion of the basin. In the Early Miocene the basin entered a passive sag phase, in which depositional relief decreased, resulting in the first evidence of widespread marine influence in the basin. An important shift in stress patterns during the Mid Miocene caused pre-existing extensional lows to be folded into east-west anticlines of the Sunda Fold Belt, such as the Jambu-Liang structure containing Cendor (and most of the basin s producing fields). The reserve estimates included herein for the Cendor Field were based upon volumetric estimates. The drive mechanism is expected to be a fluid expansion drive with supplemental pressure support achieved through water injection. Future Production Rates-All Fields Initial production rates are based on the current producing rates for those wells now on production. Test data and other related information was used to estimate the anticipated initial production rates for RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

118 Petrofac Limited September 21, 2005 Page 9 those wells or locations, which are not currently producing. If no production decline trend has been established, future production rates were established by using type curve method based on simulation work and well performance. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. The future production rates from wells now on production may be more or less than estimated because of changes in marketing conditions or allowable set by regulatory bodies. Wells or locations, which are not currently producing, may start producing earlier or later than anticipated in our estimates of their future production rates. Projections of future reserves for the Cendor Field are shown in the following table utilizing the projected production start date during the third quarter of Projection of Future Reserves Cendor Field, Offshore Malaysia As of June 30, 2005 PROVED UNDEVELOPED PROBABLE UNDEVELOPED PROVED + PROBABLE YEAR BO/YR BOPD BO/YR BOPD BO/YR BOPD ,577,400 4, ,577,400 4, ,163,932 11, ,163,932 11, ,779,003 10, ,779,003 10, ,284,524 8, ,284,524 8, ,921,674 8, ,921,674 8, ,598,078 7, ,598,078 7, ,405,018 6, ,405,018 6, ,329,509 6, ,329,509 6, ,554,107 4, ,451 1,486 2,096,558 5, ,886,902 5,170 1,886,902 5, ,698,212 4,653 1,698,212 4, ,528,391 4,187 1,528,391 4,187 TOTAL 24,613,245 5,655,957 30,269,201 A similar table depicting future annual production volumes by reserve category for the Ohanet Field has not been included within this CPR as a result of Petrofac s decision to include only future revenue streams for this field in their UKLA filing in lieu of net hydrocarbon volumes. Hydrocarbon Prices The future hydrocarbon price parameters used in this report reflect Petrofac's estimates of future crude pricing. Petrofac's estimate of future crude pricing utilized Brent Crude as a benchmark and appropriate adjustments for gravity, quality, local conditions and transportation fees to determine effective netback pricing for each property based upon historical differentials between Brent Crude and the realized regional pricing. These estimates of future prices are summarized as follows: RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

119 Petrofac Limited September 21, 2005 Page 10 ESTIMATE OF FUTURE PRODUCT PRICING OHANET FIELDS AND CENDOR FIELD AS OF JUNE 30, 2005 BASE CASE ASSUMPTIONS BRENT CRUDE OHANET NETBACK CENDOR NETBACK YEAR PRICING, $/BBL PRICING, $/BBL OF NGL's PRICING $/BBL OF OIL 2005 $ $ $ $ $ $ $ $ $ $ $ $ AND AFTER $ $ $ LOWSIDE CASE ASSUMPTIONS BRENT CRUDE OHANET NETBACK CENDOR NETBACK YEAR PRICING, $/BBL PRICING, $/BBL OF NGL's PRICING $/BBL OF OIL 2005 $ $ $ $ $ $ $ $ $ $ $ $ AND AFTER $ $ $ HIGHSIDE CASE ASSUMPTIONS BRENT CRUDE OHANET NETBACK CENDOR NETBACK YEAR PRICING, $/BBL PRICING, $/BBL OF NGL's PRICING $/BBL OF OIL 2005 $ $ $ $ $ $ $ $ $ $ $ $ AND AFTER $ $ $ Costs Operating costs utilized within this report were based upon the projected values supplied by Petrofac include only those costs directly applicable to the operation of the fields. Petrofac has prepared their estimates of future operating costs utilizing recent actual operating statements and associated data. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the fields under terms of operating agreements. Our review of the operating statements indicates that the formatting and documentation of these statements are consistent with industry standards. Except for the contractual 1st oil payment to Amerada Hess for the Cendor Field, no deductions were made for indirect costs such as loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the properties. Development Costs Development costs were furnished to us by Petrofac and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. For Ohanet, we have assumed no abandonment costs, as these are not part of the scope of work included in the financial envelope. Such costs, if any are required and expended during the contract, will be provisioned either as costrecoverable operating costs, or as a legislative requirement thus expanding the financial envelope. However, it should be noted that abandonment provisions have been made as part of the economic requirements of the Cendor PSC and are included in the cost basis thereof. Ryder Scott has not performed a detailed study of the abandonment costs nor the salvage value and makes no warranty for this assumption. As you have requested, current costs were utilized without escalation until depletion of the properties. Sensitivity Cases Ryder Scott has examined the sensitivity of the following parameters which could impact the evaluation of these reserves for the Cendor Field: RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

120 Petrofac Limited September 21, 2005 Page 11 Minimum Oil Pricing Case Base case pricing scenario less $5.00 per barrel Maximum Oil Pricing Case Base case pricing scenario plus $5.00 per barrel Petrofac has assumed unescalated costs for the base case scenario and for each of these sensitivity cases. The results of these sensitivity cases are as follows: Cendor Field, Offshore Malaysia Brent Proved Only (1P) Proved + Probable (2P) Crude Discount Rate Discount Rate $ per Bbl Case 8.0% 10.0% 12.0% 8.0% 10.0% 12.0% NPV, $000 NPV, $000 NPV, $000 NPV, $000 NPV, $000 NPV, $000 $ Lowside $ 34,506 $ 32,310 $ 30,313 $ 36,251 $ 33,802 $ 31,593 $ Base $ 45,061 $ 42,236 $ 39,674 $ 47,653 $ 44,411 $ 41,505 $ Highside $ 55,285 $ 51,763 $ 48,581 $ 59,473 $ 55,249 $ 51,495 General This evaluation has been supervised by the undersigned, Mr. Douglas L. McBride, Senior Vice President-International of Ryder Scott Company, LP. Mr. McBride is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Engineers, and a member of the Society of Professional Well Log Analysts. Mr. McBride has 30 years of upstream oil and gas industry experience. Ryder Scott Company is a professional limited liability partnership incorporated in the State of Texas with head offices located at 1100 Louisiana, Suite 3800, Houston, Texas 77002, USA. With a staff of 130 employees, Ryder Scott also maintains offices in Denver and Calgary as well as affiliated offices in London, Moscow and Beijing. The firm has provided petroleum consulting services throughout the world since The firm's professional engineers, geologists, geophysicists, petrophysicists, and economists are engaged in the independent appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations and field studies. Ryder Scott Company generates all revenues based solely upon the professional fees received for services rendered in the evaluation of oil and gas properties. Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties. The estimates of reserves presented herein are based upon a detailed study of the Algerian and Malaysian assets in which Petrofac owns an interest. The existence of the two fields included within this evaluation is substantiated by the details of drilling results, actual historical production data, analysis or other evidence and takes account of all relevant information. A field examination of the properties was not considered necessary for the purposes of this report. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Petrofac has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by Petrofac were accepted without independent verification. The economic results indicated within this report have been prepared utilizing the contractual terms of the RSC and PSC as supplied by Petrofac. The contractual terms of these agreements appear to be within industry standards. The estimates presented in this report are based on data available through June, RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

121 Petrofac Limited September 21, 2005 Page 12 Petrofac has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. Very truly yours, RYDER SCOTT COMPANY, L.P. Douglas L. McBride, P.E. Senior Vice President-International RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

122 Petrofac Limited September 21, 2005 Page 13 ATTACHMENT NO. 1A 10 W 5 W 0 E 5 E 10 E SPAIN Mediterranean Sea ALGIERS Atlantic Ocean TUNISIA MOROCCO HASSI R'MEL HASSI MESSAOUD LIBYA 25 N MAURITANIA ALGERIA 25 N MALI NIGER 20 N 20 N 30 N 30 N 35 N 35 N 10 W 5 W 0 E 5 E 10 E Km Source: Wood Mackenzie RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

123 Petrofac Limited September 21, 2005 Page 14 ATTACHMENT NO. 1B 29 N 28 30'N 28 N 8 E 8 30'E Ouan 9 E 9 30'E 10 E Sedoukhane 244b GZ-101 Erg Timellouline-101 Ouan Tin Oufar-1 Temaroualine-101 Ouan Essar Sedoukhane 1 Est TMLS 1 223a a MEREKSEN NC169 A 1 Tinrhert Tinrhert Eni 1 Dimeta Nord G1-26 Tamadanet-1 HIM Ain Antar A10 Tesselit c Dimeta NW-1 1 A5 Sonatrach 239 BOU-1 DIMETA OUEST Stah NW-1 WAFA Tinrhert Tahala Nord 1 W-2 A6 1 A7 BHP Billiton Sonatrach A4 Oued Ahara-101 Tinrhert E-1 W-1 2El Ksar oil A3 A9 Garet Tisselit-1 OHANET 1 Ouine Eslak-101 STAH A1 BHP A-101 N-1 Guelta Nord E-101 A8 THLS Timissit Timissit Billiton A A2 Ohanet N-1 GUELTA ALRAR 2 T-North Alrar-1 N-102 IN ADAOUI 1 Tesselit-1,101 OEL-1 Gara Brune 2 D3-52 A1-52 ASKARENE Fersig-1 TMN-1 N-101 Djebel TAMADANET 103OES-2Sonatrach E4 245 South Timedratine E3 D2-52 El Louh-1 S Ohanet S N OES-1 1 Rosneft Timedratine N AC-1 A1 D1-52 B1,101,102 E-2 Ohanet S-1 TIMEDRATINE OUEST A2 In Alrar W-1 E-1 Ouarene Tilmas TAK-1 Akamil ACHEB OUEST Djebel Mzi-1 Alrar North-1 North 2 3 Ouarene-1 Ouan ACHEB Alrar C NC175A 1 In Akamil Taradjeli 095 Taouratine Eni IFT Alrar S 2 Open Ouarene S-1 Taouratine-4 Trig N. 1 N-2 Djoua 2 N a TAKS-1 Trig Ifefane Trig-E-1 N a Alrar IN AMENAS N ZARZAITINE NE EDEYEN 2 gas, LPG, 1 1 Gara NE-1 I1-1 Irlalene condensate In Amenas N IH (under construction) GARA N-3 ZARZAITINE Tan Baloul S-2 1 In Amenas W-1 In EOR Project W Amenas E-1 Gara S-2 1 Sinopec Gara S IN AMENAS Medex S-1 W-2 NTR-1 Taouratine Gour 1 Sonatrach Ihansatene-1 2 W-1 N-1 B-1 LA RECULEE 233 Tiedou-1 2 S-1 4 Tihalatine Arene 2 Tiguentourine TGN-1 1 Tihigaline B-1 Centre-1 A-1 TIDERER 1 Tihalatine C BP 3 Tihalatine Ihansatene W 7 Tenere Gour Laoud-1 Ihansatene Remal-1 El Beugra 125 SW-1 WHA-1 TGE-1 Gour Ahmar-1 Taouratine HFN-1 HASSI Tihigaline C-2 EDJELEH Tihigaline D-1 Zaouatene OUAN HOS-1 In Louiam-1 TIGUENTOURINE HFO ABECHEU Tihigaline-2 BP 1 NC210 S-1 BP W-1 BP 2 Woodside Couloir Tihigaline C HASSI FARIDA 3 Nord Bourarhet Sud 4 2 HOAS-1 Erg Bourarhet BP 1 OUAN TAREDERT T h b t 1 8 E 8 30'E 9 E 9 30'E 10 E Km NH 2 30" Ohanet-Haoud El Hamra condensate pipeline OH1 30" Ohanet-Haoud El Hamra oil pipeline Alrar-HassiR'Melpipelines: GR1/GR242"/48" gaspipeline LR130" LPG oil oil oil oil oil oil oil ALGERIA oil LIBYA 29 N 28 30'N 28 N 27 30'N Source: Wood Mackenzie RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

124 A E Connaught Port Bridge Kelang Dumai Refinery & Termi nal KL Power Station Riau Andal an pulp and paper mill Su ng e i Pa k nin g Re fin e ry & T e rm in a l Ku ra u Pro c es s Pla nt Segamat Operations Cen tre A B 1 B A A D D B C F C A Hang Tuah B A Petrofac Limited September 21, 2005 Page 15 ATTACHMENT NO. 2A 100 E 102 E 104 E 106 E 8 N South China Sea 8 N Malaysia-Thailand JDA Malaysia-Vietnam CAA THAILAND MALAYSIA Natuna Sea KUALA LUMPUR 2 N 2 N 4 N 4 N 6 N 6 N INDONESIA SINGAPORE Km E 102 E 104 E 106 E Source: Wood Mackenzie RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

125 Petrofac Limited September 21, 2005 Page 16 ATTACHMENT NO. 2B 'E 5 45'N 5 30'N 5 15'N 5 N 4 45'N PM306 Petronas Carigali 'E PM314 Talisman 8" Jerneh-TCOT liquids pipeline Cengal-1 28" Jerneh-Kerteh gas pipeline 'E Meranti 6F Meranti 6F-11.1 Ipoh-1 Beranang NW PM6 Petronas Carigali 28" Resak-Kerteh gas pipeline A, CPP RESAK E 1-3 PM6 Petronas Carigali 3 6F B Tunggal B Chenang 'E 2 A Tabu-2 PM304 Petrofac Ketumbar Semangkok Timur oil 2 2 SEMANGKOK Telok Kemang-1 Jambu-2 Liang-4 Jambu-1 1 Liang-3 Liang-2 Jambu-4 2 Desaru-1 Jambu-3 Liang-1 1 Ridan 'E Tembikai 1 24" oil pipeline to TCOT IRONG BARAT PM30 Talism Open South Angsi-1/ ST1/ST2 Oren-1 32" gas pipeline to Kerteh 1 Serok 30" gas pipeline to Kerteh Laba-1 Laba Barat 5 Telok 2 Mutiara CPP 6 PM12 T Telo Cendor 3, Sou Petronas Carigali B B 'N 5 30'N 5 15'N 5 N 4 45'N 4 30'N Paka Power Station Kerteh Oil Terminal Terengganu Crude Oil Terminal (TCOT) Kerteh Gas Plant PM307 Petronas Carigali PM12 Petrona Carigali Jelutong 5G 'N 'E 'E 'E 104 E 'E 'E Km Source: Wood Mackenzie RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

126 Petrofac Limited September 21, 2005 Page 17 ATTACHMENT NO. 3 CENDOR TOP H-15 DEPTH MAP (M TVDSS) RYDER SCOTT COMPANY PETROLEUM CONSULTANTS