Petrofac Limited

PETROFAC LIMITED (incorporated with limited liability in Jersey with registered number 81792) US$750,000,000 3.400% Senior Notes due 2018 irrevocably and unconditionally guaranteed by Petrofac International Ltd and Petrofac International (UAE) LLC Petrofac Limited, a company incorporated under the laws of Jersey (the “Company” or the “Issuer”), is offering (the “Offering”) an aggregate principal amount of US$750,000,000 3.400% Senior Notes due 2018 (the “Notes”). Petrofac International Ltd and Petrofac International (UAE) LLC (the “Guarantors”) will irrevocably and unconditionally guarantee, jointly and severally, the due and prompt payment of all amounts at any time becoming due and payable in respect of the Notes under the deeds of guarantee (the “Guarantees”). The Notes and the Guarantees will be issued pursuant to a Fiscal and Paying Agency Agreement (the “Fiscal and Paying Agency Agreement”) dated 10 October 2013, among the Company, the Guarantors and Citibank, N.A., London Branch, as fiscal agent, paying agent and transfer agent (referred to herein as the “Paying Agent”) and Citigroup Global Markets Deutschland AG, as registrar (the “Registrar”).

The Company will pay interest on the Notes at an annual rate equal to 3.400% of their outstanding principal amount. Interest on the Notes is payable semi-annually in arrears on 10 April and 10 October of each year, commencing on 10 April 2014. Payments on the Notes (including payments by the Guarantors under the Guarantees) will be made without withholding or deduction for or on account of taxes, unless such withholding or deduction is required by law. In the event of any withholding or deduction for or on account of taxes of a jurisdiction in which the Company or a Guarantor is organised or resident for tax purposes or a jurisdiction through which payment in respect of any Note is made, the Company or (as the case may be) the Guarantors will, subject to certain exceptions and limitations, pay additional amounts to the holder of any Note to the extent described in the terms and conditions of the Notes under “Description of Notes and Guarantees”. The Company may redeem the Notes in whole but not in part at 100% of the principal amount thereof, plus accrued and unpaid interest, in the event of certain taxation changes and otherwise as described under “Description of Notes and Guarantees”.

The Notes will be senior unsecured obligations of the Company and will rank equally in right of payment with the Company’s other existing and future unsecured and unsubordinated indebtedness. The Guarantees will be a senior unsecured obligation of each Guarantor and will rank equally in right of payment with all existing and future senior unsecured and unsubordinated obligations of such Guarantor.

This offering memorandum (the “Offering Memorandum”) constitutes listing particulars for the purpose of the application and has been approved by the Irish Stock Exchange. Application has been made to the Irish Stock Exchange for the Notes to be admitted to the official list (the “Official List”) and trading on the Global Exchange Market. No assurance can be given that the application will be granted. Furthermore, admission of the Notes to the Official List and trading on the Global Exchange Market is not an indication of the merits of the Company, the Guarantors, the Notes or the Guarantees. References in this Offering Memorandum to Notes being “listed” (and all related references) shall mean that such Notes have been admitted to trading on the Global Exchange Market of the Irish Stock Exchange. There can be no assurance that a trading market in the Notes will develop or be maintained.

AN INVESTMENT IN THE NOTES INVOLVES A HIGH DEGREE OF RISK. SEE THE SECTION BEGINNING ON PAGE 16 OF THIS OFFERING MEMORANDUM ENTITLED “RISK FACTORS”.

The Notes and the Guarantees (together, the “Securities”) have not been and will not be registered under the US Securities Act of 1933, as amended (the “Securities Act”), or under any securities laws of any other jurisdiction. Subject to certain exemptions, or transactions not subject to, the Securities Act, the Securities 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”)). The Securities will be offered and sold outside the United States to non-US persons in offshore transactions as defined in and in reliance on Regulation S and in the United States only to qualified institutional buyers (“QIBs”) (within the meaning of Rule 144A under the Securities Act), in reliance on an exemption from registration pursuant to Rule 144A under the Securities Act (“Rule 144A”). Prospective purchasers of the Securities are hereby notified that the seller of the Securities may be relying on the exemption from the provisions of Section 5 of the Securities Act provided by Rule 144A. The Company has not been and will not be registered under the US Investment Company Act of 1940. Neither the US Securities and Exchange Commission (the “SEC”) nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this Offering Memorandum. Any representation to the contrary is a criminal offence. The Notes are subject to restrictions on transferability and resale and may not be transferred or resold except as permitted under the Securities Act and applicable state securities laws pursuant to registration thereunder or exemption therefrom. For a description of these and certain further restrictions on the transfer of the Notes, see “Notice to Investors”.

Price of the Notes: 99.627% plus accrued interest, if any, from 10 October 2013. The Notes will be offered and sold in minimum denominations of US$2,000 and integral multiples of US$1,000 in excess thereof. The Notes are being offered subject to various conditions and are expected to be delivered on or about 10 October 2013 through the facilities of The Depository Trust Company (“DTC”) and its participants, including Euroclear Bank, S.A./N.V. (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”).

It is expected that the Notes will be rated BBB+ by Standard & Poor’s Financial Services LLC, a division of The McGraw-Hill Companies, Inc. (“S&P”) and Baa1 by Moody’s Investors Service Ltd (“Moody’s”), subject to confirmation at closing. A rating is not a recommendation to buy, sell or hold securities and may be subject to revision, suspension or withdrawal at any time by the assigning rating organisation. Each of S&P and Moody’s (which each provide ratings in relation to the Company and its subsidiaries (the “Group”) and the Notes) are established in the European Union and registered in accordance with Regulation (EU) No 1060/2009. Joint Bookrunners Barclays J.P. Morgan Deutsche Bank Securities RBS The date of this Offering Memorandum is 7 October 2013 TABLE OF CONTENTS

Page IMPORTANT INFORMATION ...... ii STABILISATION ...... iii NOTICE TO NEW HAMPSHIRE RESIDENTS ...... iii NOTICE TO EUROPEAN ECONOMIC AREA INVESTORS ...... iv NOTICE TO US INVESTORS ...... v FORWARD-LOOKING STATEMENTS ...... vi PRESENTATION OF FINANCIAL AND OTHER INFORMATION ...... vii CURRENCY PRESENTATION ...... x EXCHANGE RATE INFORMATION ...... xi OVERVIEW ...... 1 RISK FACTORS ...... 16 USE OF PROCEEDS ...... 31 CAPITALISATION ...... 32 SELECTED FINANCIAL STATEMENTS AND OTHER DATA ...... 33 OPERATING AND FINANCIAL REVIEW ...... 40 BUSINESS ...... 76 DIRECTORS AND SENIOR MANAGEMENT ...... 96 PRINCIPAL SHAREHOLDERS ...... 102 THE GUARANTORS ...... 103 DESCRIPTION OF NOTES AND GUARANTEES ...... 105 BOOK-ENTRY, DELIVERY AND FORM ...... 121 TAXATION ...... 125 PLAN OF DISTRIBUTION ...... 129 NOTICE TO INVESTORS ...... 132 LEGAL MATTERS ...... 135 INDEPENDENT AUDITORS ...... 136 WHERE YOU CAN FIND MORE INFORMATION ...... 137 SERVICE OF PROCESS AND ENFORCEMENT OF JUDGMENTS ...... 138 LISTING AND GENERAL INFORMATION ...... 140 GLOSSARY ...... 142 INDEX TO FINANCIAL STATEMENTS ...... F-1

i IMPORTANT INFORMATION

In this Offering Memorandum we refer to information and statistics regarding our industry based on information we have or have obtained from sources we believe to be reliable. We have summarised certain documents and other information in a manner we believe to be accurate, but we refer you to the actual documents for a more complete understanding of the matters we discuss in this Offering Memorandum. We will make copies of actual documents available to you upon request. None of us, nor Barclays Capital Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBS Securities Inc. (the “Initial Purchasers”) represents that the information herein is complete. The information in this Offering Memorandum is current only as of the date on the cover, and our business or financial position and other information in this Offering Memorandum may change after that date. You should consult your own legal, tax and business advisers regarding an investment in the Notes, including the merits and risks involved. Information in this Offering Memorandum is not legal, tax or business advice.

You should base your decision to invest in the Notes solely on information contained in this Offering Memorandum. Neither we nor the Initial Purchasers have authorised anyone to provide you with any different information.

We are offering the Notes, and the Guarantors will issue the Guarantees, in reliance on an exemption from registration under the Securities Act for an offer and sale of securities that does not involve a public offering. If you purchase the Notes, you will be deemed to have made certain acknowledgments, representations and warranties as detailed under “Notice to Investors”. You may be required to bear the financial risk of an investment in the Notes for an indefinite period. Neither we nor the Initial Purchasers are making an offer to sell the Notes in any jurisdiction where the offer and sale of the Notes is prohibited. We do not make any representation to you that the Notes are a legal investment for you. No action has been, or will be, taken to permit a public offering in any jurisdiction where action would be required for that purpose.

Each prospective purchaser of the Notes must comply with all applicable laws and rules and regulations in force in any jurisdiction in which it purchases, offers or sells the Notes and must obtain any consent, approval or permission required by it for the purchase, offer or sale by it of the Notes under the laws and regulations in force in any jurisdiction to which it is subject or in which it makes such purchases, offers or sales, and neither we nor the Initial Purchasers shall have any responsibility therefore.

None of the US Securities and Exchange Commission, any US state securities commission nor any non-US securities authority or other authority has approved or disapproved of the Notes or determined if this Offering Memorandum is truthful or complete. Any representation to the contrary is a criminal offence.

The Company and the Guarantors accept responsibility for the information contained in this Offering Memorandum. The Company and Guarantors have made all reasonable inquiries and confirm to the best of their knowledge that the information contained in this Offering Memorandum is in accordance with the facts and does not omit anything likely to affect the import of such information.

The Initial Purchasers make no representation or warranty, express or implied, as to the accuracy or completeness of the information contained in this Offering Memorandum. Nothing contained in this Offering Memorandum is, or shall be relied upon as, a promise or representation by the Initial Purchasers as to the past or future. We have furnished the information contained in this Offering Memorandum. The Initial Purchasers assume no responsibility for the accuracy or completeness of any of the information contained herein.

We have prepared this Offering Memorandum solely for use in connection with the offer of the Notes to QIBs under Rule 144A under the Securities Act and to non-US persons outside the United States under Regulation S under the Securities Act. You agree that you will hold the information contained in this Offering Memorandum and the transactions contemplated hereby in confidence. You may not distribute this Offering Memorandum to any person, other than a person retained to advise you in connection with the purchase of the Notes.

This Offering Memorandum does not constitute an offer to sell or an invitation to subscribe for or purchase any of the Notes in any jurisdiction in which such offer or invitation is not authorised or to any person to whom it is unlawful to make such an offer or invitation. Laws in certain jurisdictions may restrict the distribution of this Offering Memorandum and the offer and sale of the Notes. Persons into whose possession this Offering Memorandum or any of the Notes are delivered must inform themselves about and observe those restrictions. Each prospective purchaser of the Notes must comply with all applicable laws and regulations in force in any

ii jurisdiction in which it purchases, offers or sells the Notes or possesses or distributes this Offering Memorandum. In addition, each prospective purchaser must obtain any consent, approval or permission required under the regulations in force in any jurisdiction to which it is subject or in which it purchases, offers or sells the Notes. Neither we nor the Initial Purchasers shall have any responsibility for obtaining such consent, approval or permission.

We and the Initial Purchasers may reject any offer to purchase the Notes in whole or in part, sell less than the entire principal amount of the Notes offered hereby or allocate to any purchaser less than all of the Notes for which it has subscribed.

The information set out in relation to sections of this Offering Memorandum describing clearing and settlement arrangements, including the section entitled “Book-Entry, Delivery and Form”, is subject to change in or reinterpretation of the rules, regulations and procedures of DTC currently in effect. While we accept responsibility for accurately summarising the information concerning DTC, we accept no further responsibility in respect of such information.

We cannot guarantee that our application for the admission of the Notes to be listed on the Official List of the Irish Stock Exchange and to be traded on the Global Exchange Market of the Irish Stock Exchange will be approved as of the settlement date for the Notes or at any time thereafter, and settlement of the Notes is not conditioned on obtaining this listing.

The Notes are subject to restrictions on transferability and resale and may not be transferred or resold except as permitted under the Securities Act and applicable securities laws of any other jurisdiction pursuant to registration or exemption therefrom. Prospective purchasers should be aware that they may be required to bear the financial risks of this investment for an indefinite period of time. Please see “Notice to Investors”.

We reserve the right to withdraw this Offering of the Notes at any time. We and the Initial Purchasers also reserve the right to reject any offer to purchase the Notes in whole or in part for any reason or no reason and to allot to any prospective purchaser less than the full amount of the Notes sought by it.

Arthur Cox Listing Services Limited is acting solely in its capacity as listing agent for the Company in relation to the Notes and is not itself seeking admission of the Notes to the Official List of the Irish Stock Exchange or to trading on the Global Exchange Market of the Irish Stock Exchange.

STABILISATION

IN CONNECTION WITH THE OFFERING OF THE NOTES, BARCLAYS CAPITAL INC. AND J.P. MORGAN SECURITIES LLC (THE “STABILISING MANAGERS”) (OR PERSONS ACTING ON THEIR BEHALF) MAY OVER-ALLOT NOTES OR EFFECT TRANSACTIONS WITH A VIEW TO SUPPORTING THE MARKET PRICE OF THE NOTES AT A LEVEL HIGHER THAN THAT WHICH MIGHT OTHERWISE PREVAIL. HOWEVER, THERE IS NO ASSURANCE THAT THE STABILISING MANAGERS (OR PERSONS ACTING ON THEIR BEHALF) WILL UNDERTAKE STABILISATION ACTION. ANY STABILISATION ACTION MAY BEGIN ON OR AFTER THE DATE ON WHICH ADEQUATE PUBLIC DISCLOSURE OF THE FINAL TERMS OF THE OFFER OF THE NOTES IS MADE AND, IF BEGUN, MAY BE ENDED AT ANY TIME, BUT MUST END NO LATER THAN 30 DAYS AFTER THE DATE ON WHICH THE COMPANY RECEIVED THE PROCEEDS OF THE ISSUE OR NO LATER THAN 60 DAYS AFTER THE DATE OF THE ALLOTMENT OF THE NOTES WHICHEVER IS THE EARLIER. ANY STABILISATION ACTION OR OVER-ALLOTMENT MUST BE CONDUCTED BY THE STABILISING MANAGERS (OR PERSONS ACTING ON THEIR BEHALF) IN ACCORDANCE WITH ALL APPLICABLE LAWS AND RULES.

NOTICE TO NEW HAMPSHIRE RESIDENTS

NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A LICENCE HAS BEEN FILED UNDER CHAPTER 421-B OF THE NEW HAMPSHIRE REVISED STATUTES, ANNOTATED 1995, AS AMENDED, WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN

iii THE STATE OF NEW HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE OF THE STATE OF NEW HAMPSHIRE THAT ANY DOCUMENT FILED UNDER CHAPTER 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR A TRANSACTION MEANS THAT THE SECRETARY OF STATE OF THE STATE OF NEW HAMPSHIRE HAS PASSED IN ANY WAY UPON THE MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON, SECURITY OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY PROSPECTIVE PURCHASER, CLIENT OR CUSTOMER ANY REPRESENTATION INCONSISTENT WITH THE PROVISIONS OF THIS PARAGRAPH.

NOTICE TO EUROPEAN ECONOMIC AREA INVESTORS

This Offering Memorandum has been prepared on the basis that the offer and sale of the Notes will be made pursuant to an exemption under the Prospectus Directive, as implemented in member states of the European Economic Area (“EEA”), from the requirement to produce and publish a prospectus which is compliant with the Prospectus Directive, as so implemented, for offers of the Notes. Accordingly, any person making or intending to make any offer within the EEA or any of its member states (each a “Member State”) of the Notes which are the subject of the placement referred to in this Offering Memorandum must only do so in circumstances in which no obligation arises for the Company or the Initial Purchasers to produce and publish a prospectus which is compliant with the Prospectus Directive, including Article 3 thereof, as so implemented, for such offer. For EEA jurisdictions that have not implemented the Prospectus Directive, all offers of the Notes must be in compliance with the laws of such jurisdictions. Neither the Company nor the Initial Purchasers have authorised, nor do they authorise, the making of any offer of the Notes through any financial intermediary, other than offers made by the Initial Purchasers, which constitute a final placement of the Notes.

In relation to each Member State that has implemented the Prospectus Directive (each, a “Relevant Member State”), each Initial Purchaser has represented and agreed that, with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State, it has not made and will not make an offer of the Notes which are the subject of the Offering contemplated by this Offering Memorandum to the public in that Relevant Member State other than: (i) to any legal entity which is a “qualified investor” within the meaning of Article 2(1)(c) of the Prospectus Directive; (ii) to fewer than 100 natural or legal persons or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive); or (iii) in any other circumstances falling within Article 3(2) of the Prospectus Directive; provided that no such offer of the Notes shall require the Company or the Initial Purchasers to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

Each subscriber for, or purchaser of, the Notes in this Offering located within a Relevant Member State will be deemed to have represented, acknowledged and agreed that it is a “qualified investor” within the meaning of Article 2(1)(e) of the Prospectus Directive.

For the purposes of the above, the expression an “offer of notes to the public” in relation to any Notes in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the Notes to be offered so as to enable an investor to decide to purchase or subscribe for the Notes, as such expression may be varied in the Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State. For the purposes of the above, the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including Directive 2010/73/EU, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State.

Jersey. A copy of this document has been delivered to the registrar of companies in Jersey (the “Jersey Registrar”) in accordance with Article 5 of the Companies (General Provisions) (Jersey) Order 2002, and the Jersey Registrar has given, and has not withdrawn, his consent to its circulation. The Jersey Financial Services Commission (the “Commission”) has given, and has not withdrawn, or will have given prior to the issue of the

iv Notes and not withdrawn, its consent under Article 4 of the Control of Borrowing (Jersey) Order 1958 to the issue of the Notes. The Commission is protected by the Control of Borrowing (Jersey) Law 1947, as amended, against liability arising from the discharge of its functions under that law. It must be distinctly understood that, in giving these consents, neither the Jersey Registrar nor the 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.

If you are in any doubt about the contents of this document you should consult your stockbroker, bank manager, solicitor, accountant or other financial advisor. It should be remembered that the price of securities and the income from them can go down as well as up.

Switzerland. This Offering Memorandum does not constitute an issue prospectus pursuant to Article 652a or Article 1156 of the Swiss Code of Obligations and the Notes will not be listed on the SIX Swiss Exchange. Therefore, this Offering Memorandum may not comply with the disclosure standards of the Swiss Code of Obligations and/or the listing rules (including any prospectus schemes) of the SIX Swiss Exchange. Accordingly, the Notes may not be offered to the public in or from Switzerland, but only to a selected and limited circle of investors, which do not subscribe to the Notes with a view to distribution.

United Kingdom. This Offering Memorandum is for distribution only to, and is only directed at, persons who (i) have professional experience in matters relating to investments falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, (the “Financial Promotion Order”), (ii) are persons falling within Article 49(2)(a) to (d) of the Financial Promotion Order (high net worth companies, unincorporated associations, etc.) or (iii) are persons to whom an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000 (“FSMA”)) in connection with the issue or sale of any Notes may otherwise lawfully be communicated (all such persons under (i) through (iii) together being referred to as “relevant persons”). This Offering Memorandum is directed only at relevant persons and must not be acted on or relied on by persons who are not relevant persons. Any investment or investment activity to which this Offering Memorandum relates is available only to relevant persons and will be engaged in only with relevant persons. Any person who is not a relevant person should not act or rely on this Offering Memorandum or any of its contents.

NOTICE TO US INVESTORS

This Offering is being made in the United States in reliance upon an exemption from registration under the Securities Act for an offer and sale of the Notes which does not involve a public offering. In making your purchase, you will be deemed to have made certain acknowledgments, representations and agreements. Please see “Notice to Investors”.

This Offering Memorandum is being provided (1) to a limited number of US investors that the Company reasonably believes to be “qualified institutional buyers” under Rule 144A of the Securities Act for informational use solely in connection with their consideration of the purchase of the Notes, and (2) to non-US Persons outside the United States in connection with offshore transactions in reliance on Regulation S of the Securities Act. The Notes and the Guarantees described in this Offering Memorandum have not been registered with, recommended by or approved by the SEC, any state securities commission in the United States or any other securities commission or regulatory authority, nor has the SEC, any state securities commission in the United States or any such securities commission or authority passed upon the accuracy or adequacy of this Offering Memorandum. Any representation to the contrary is a criminal offence.

THIS OFFERING MEMORANDUM CONTAINS IMPORTANT INFORMATION WHICH YOU SHOULD READ BEFORE YOU MAKE ANY DECISIONS WITH RESPECT TO AN INVESTMENT IN THE NOTES.

v FORWARD-LOOKING STATEMENTS

This Offering Memorandum includes “forward-looking statements” within the meaning of the US securities laws and certain other jurisdictions, based on our current expectations and projections about future events. All statements other than statements of historical facts included in this Offering Memorandum including, without limitation, statements regarding our future financial position, risks and uncertainties related to our business, strategy, capital expenditures, projected costs and our plans and objectives for future operations, may be deemed to be forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, including those identified under the “Risk Factors” section in this Offering Memorandum. Words such as “aim”, “anticipate”, “assume”, “believe”, “continue”, “could”, “estimate”, “expect”, “forced”, “guidance”, “intend”, “may”, “plan”, “potential”, “predict”, “projected”, “risk”, “should”, “will” and similar expressions or the negatives of these expressions are intended to identify forward-looking statements. By their nature, forward-looking statements involve known and unknown risks, uncertainties and other factors because they relate to events and depend upon circumstances that may or may not occur in the future. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Such statements are not guarantees of future performance because they are based on numerous assumptions. Any forward-looking statement speaks only as of the date on which it is made and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

The risks described in the “Risk Factors” section in this Offering Memorandum are not exhaustive. Other sections of this Offering Memorandum describe additional factors that could adversely affect our business, financial position or results of operations. We urge you to read the sections of this Offering Memorandum entitled “Operating and Financial Review” and “Business” for a more complete discussion of the factors that could affect our future performance and the markets in which we operate. Moreover, we operate in a very competitive and rapidly changing environment. New risk factors emerge from time to time and it is not possible for us to predict all such risk factors, nor can we assess the impact of all such risk factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. Given these risks and uncertainties, you should not place undue reliance on forward-looking statements as a prediction of actual results.

vi PRESENTATION OF FINANCIAL AND OTHER INFORMATION

Financial Statements This Offering Memorandum includes the following historical financial statements (the “Financial Statements”): • the unaudited interim condensed consolidated financial statements of the Company and its subsidiaries, associates and joint ventures as of and for the six months ended 30 June 2013 (including comparative financial information as of and for the six months ended 30 June 2012) (the “2013 Interim Condensed Consolidated Financial Statements”) and the notes thereto, prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”), and the independent review report thereon; • the audited consolidated financial statements of the Company and its subsidiaries, associates and joint ventures as of and for the year ended 31 December 2012 (including comparative financial information as of and for the year ended 31 December 2011) (the “2012 Consolidated Financial Statements”) and the notes thereto, prepared in accordance with IFRS, and the audit report thereon; • the audited consolidated financial statements of the Company and its subsidiaries, associates and joint ventures as of and for the year ended 31 December 2011 (including comparative financial information as of and for the year ended 31 December 2010) (the “2011 Consolidated Financial Statements”) and the notes thereto, prepared in accordance with IFRS, and the audit report thereon; and • the audited consolidated financial statements of the Company and its subsidiaries, associates and joint ventures as of and for the year ended 31 December 2010 (including comparative financial information as of and for the year ended 31 December 2009) (the “2010 Consolidated Financial Statements”, and together with the 2011 Consolidated Financial Statements and the 2012 Consolidated Financial Statements, the “Consolidated Financial Statements”) and the notes thereto, prepared in accordance with IFRS, and the audit report thereon.

New Accounting Standards and Interpretations Several new accounting standards are effective for accounting periods beginning on or after 1 January 2013. The most important new accounting standard for the Group is IFRS 11. See note 2 to the 2013 Interim Condensed Consolidated Financial Statements for a discussion of other new accounting standards and interpretations.

IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 “Jointly-controlled Entities—Non-monetary Contributions by Venturers” and removes the option to account for jointly-controlled entities (“JCEs”) using proportionate consolidation. Instead, JCEs that meet the definition of a joint venture must be accounted for using the equity method.

Certain line items for the six months ended 30 June 2012 and the year ended 31 December 2012 have been restated in the 2013 Interim Condensed Consolidated Financial Statements to reflect the impact of IFRS 11. The financial information in this Offering Memorandum for the six months ended 30 June 2012 has been derived from the 2013 Interim Condensed Consolidated Financial Statements and reflects this restatement. However, the financial information in this Offering Memorandum that has been derived from the audited Consolidated Financial Statements for the years ended 31 December 2012, 2011 and 2010 has not been restated and does not reflect the impact of IFRS 11.

Auditor’s Report See “Independent Auditors” for a description of the independent auditors’ audit and review reports, including language limiting the auditors’ scope of duty in relation to such reports and the Consolidated Financial

vii Statements to which they relate. In particular, the 26 February 2013, 2 March 2012 and 4 March 2011 reports of Ernst & Young LLP, with respect to the Financial Statements, in accordance with guidance issued by The Institute of Chartered Accountants in England and Wales, provides: “This report is made solely to the company’s members, as a body, in accordance with Article 113A of the Companies (Jersey) Law 1991 and our engagement letter dated 15 February 2011. Our audit work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditors’ report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company’s members as a body, for our audit work, for this report, or for the opinions we have formed”. The SEC would not permit such limiting language to be included in a registration statement or a prospectus used in connection with an offering of securities registered under the Securities Act, or in a report filed under the US Securities Exchange Act of 1934, as amended (the “Exchange Act”). If a US court (or any other court) were to give effect to the language quoted above, the recourse that investors in the notes may have against the independent auditors based on their reports or the consolidated financial statements to which they relate could be limited or precluded altogether.

Rounding Some financial information in this document has been rounded, and as a result the numbers shown as totals may vary slightly from the exact arithmetical aggregation of the relevant figures.

Non-IFRS Financial Information In reviewing our performance, we review the following non-IFRS financial measures to assess the performance of our reporting segments as well as the whole of our business. These are not measures determined in accordance with IFRS and should not be considered as an alternative to the applicable IFRS measures. These measures are presented because we believe that they and similar measures are widely used in our industry as a means of evaluating operating performance. These measures may not be comparable to similarly titled measures used by other companies and are not measurements under IFRS or any other body of generally accepted accounting principles, and thus should not be considered in isolation or as substitutes for the information contained in our audited financial statements, as an alternative to profit from operations before tax and finance income/(costs) or any other performance measures derived in accordance with IFRS or as an alternative to net cash flows (used in)/ generated from operating activities or any other measure of our financial performance or liquidity derived in accordance with IFRS.

EBITDA and Operating Profit EBITDA represents profit before tax adjusted for finance income, finance costs, depreciation, amortisation and impairment, as well as exceptional items such as the gain on the EnQuest demerger in 2010. We believe that EBITDA is a measure commonly reported and widely used by investors in comparing performance without regard to depreciation, which can vary significantly depending upon accounting methods, interest expense or taxation, or non-operating factors. EBITDA has been disclosed in this document because it is used by our Senior Management in determining our core performance and we believe that it permits a more complete and comprehensive analysis of our operating performance. EBITDA is not a measure determined in accordance with IFRS and our use of the term EBITDA may vary from others in our industry.

Operating profit represents profit before tax adjusted for finance income and finance costs as well as exceptional items such as the gain on the EnQuest demerger in 2010. Operating profit has been disclosed in this document because it is used by our Senior Management in determining our core performance and we believe that it permits a more complete and comprehensive analysis of our operating performance. Operating profit is not a measure determined in accordance with IFRS and our use of the term operating profit may vary from others in our industry.

Net Cash / (Debt) Net cash / (debt) comprises cash and short-term deposits, bank overdrafts, interesting bearing loans and borrowings (including the amounts utilised under our Revolving Credit Facility and project financing debt), adjusted to exclude unamortised debt acquisition costs and effective interest rate adjustments.

viii Backlog Backlog represents 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, operations, maintenance and Integrated Energy Services (“IES”) contracts, the estimated revenue attributable to the lesser of the remaining term of the contract and five years. Backlog is not booked on those IES contracts where we have entitlement to reserves. The value of a contract in a currency other than US dollars is booked at the applicable month-end exchange rate of the month in which the award is made and is revalued each month at the prevailing month-end exchange rate.

Backlog is a measure of our potential future revenue, and represents our estimate of a significant portion of anticipated future revenue. We accordingly consider backlog to be one of our key performance indicators (“KPIs”). Completion of projects at the value reflected in the backlog is subject to a number of assumptions, risks and estimates, as well as the receipt of required governmental consents, permits, and regulatory clearances, which are the responsibility of the project owner and may be outside our control. There can be no assurance that all the revenue anticipated in our backlog will be realised in the timeframe expected or at all, or will result in profits. See “Risk Factors—Our revenue, cash flows, earnings and backlog may vary in any period depending on a number of factors, including achievement of milestones on major contracts”. Further, other companies may define the uncompleted portions of their order books differently, limiting the usefulness of backlog as a comparative measure. Backlog is not a measure determined in accordance with IFRS.

Market and Industry Data This Offering Memorandum includes market share and industry data, which were obtained by us from industry publications and surveys, internal surveys and customer feedback. The market, economic and industry data have primarily been derived and extrapolated from reports provided by the International Energy Agency (“IEA”) and Douglas-Westwood.

We have accurately reproduced the market information from third-parties, and, as far as we are aware and able to ascertain, no facts have been omitted which would render the reproduced information inaccurate or misleading. The aforementioned third-party sources generally state that the information they contain has been obtained from sources believed to be reliable. These third-party sources also state, however, that the accuracy and completeness of such information is not guaranteed and that the projections they contain are based on significant assumptions. As we do not have access to the facts and assumptions underlying such market data, or statistical information and economic indicators contained in these third-party sources, we are unable to verify such information and cannot guarantee its accuracy or completeness.

Certain information in this Offering Memorandum is not based on published data obtained from independent third parties or extrapolations therefrom, but is information and statements reflecting our best estimates based upon information obtained from trade and business organisations and associations, consultants and other contacts within the industries in which we compete, as well as information published by our competitors and our internal estimates, experiences and our own interpretation of material conditions. Such information is based on the following: (i) in respect of our market position, information obtained from trade and business organisations and associations and other contacts within the industries in which we compete; (ii) in respect of industry trends, our Senior Management’s business experience and experience in the industry and the local markets in which we operate; and (iii) in respect of the performance of our operations, our internal analysis of our own audited and unaudited information. We cannot assure you that any of the assumptions that we have made in compiling this data are accurate or correctly reflect our position in our markets.

We cannot assure you that any of the assumptions underlying these statements are accurate or correctly reflect our position in the industry and none of our internal surveys or information has been verified by any independent sources. Neither we nor the Initial Purchasers make any representation or warranty as to the accuracy or completeness of this information. Neither we nor the Initial Purchasers have independently verified this information and cannot guarantee its accuracy.

Trademarks and Trade Names We own or have rights to certain trademarks or trade names that we use in conjunction with the operation of our businesses. Each trademark, trade name or service mark of any other company appearing in this Offering Memorandum is the property of its respective holder.

ix CURRENCY PRESENTATION

In this document, references to “US dollars”, “US$” and “$” are to the United States dollar and references to “cents” are to United States cents, each the lawful currency of the United States of America. References to “sterling”, “pounds sterling”, “pound”, “£”, “pence” and “p” are to the lawful currency of the United Kingdom. References to “€”or“euro” and “euro cents” are to the single currency of the participating Member States in the Third Stage of European and Monetary Union of the Treaty Establishing the European Community, as amended from time to time.

x EXCHANGE RATE INFORMATION

The following tables show, for the periods indicated, the high, low, average and period end Bloomberg Composite Rate expressed as US dollar per £1.00. The Bloomberg Composite Rate is a “best market” calculation, in which at any point in time, the bid rate is equal to the highest bid rate of all contributing bank indications and the ask rate is set to the lowest ask rate offered by these banks. The Bloomberg Composite Rate is a mid value rate between the applied highest bid rate and the lowest ask rate. The rates may differ from the actual rates used in the preparation of the Financial Statements and other financial information appearing in this Offering Memorandum. None of the Company, the Guarantors or the Initial Purchasers represent that the US dollar amounts referred to below could be or could have been converted into pounds sterling at any particular rate indicated or any other rate.

The average rate for a year means the average of the Bloomberg Composite Rates on the last day of each month during a year. The average rate for a month, or for any shorter period, means the average of the daily Bloomberg Composite Rates during that month, or a shorter period, as the case may be.

US dollar per £1.00 Period Year High Low Average(1) End 2008 ...... 1.9923 1.4629 1.8430 1.4629 2009 ...... 1.6714 1.4316 1.5722 1.6173 2010 ...... 1.6041 1.4538 1.5427 1.5612 2011 ...... 1.6706 1.5549 1.6092 1.5549 2012 ...... 1.6248 1.5406 1.5928 1.6248

Period Month High Low Average(2) End March 2013 ...... 1.5231 1.4903 1.5083 1.5199 April 2013 ...... 1.5532 1.5103 1.5309 1.5532 May 2013 ...... 1.5573 1.5040 1.5288 1.5200 June 2013 ...... 1.5722 1.5212 1.5497 1.5212 July 2013 ...... 1.5390 1.4867 1.5187 1.5208 August 2013 ...... 1.5666 1.5120 1.5505 1.5504 September 2013 (through 26 September 2013) ...... 1.6146 1.5544 1.5844 1.6041 (1) The average of the exchange rates on the last business day of each month during the relevant period. (2) The average of the exchange rates on each business day during the relevant period.

The exchange rate of the US dollar to pound sterling on 26 September 2013 was US$1.6041 = £1.

The above rates may differ from the actual rates used in the preparation of the Financial Statements and other financial information appearing in this Offering Memorandum. Our inclusion of these exchange rates is not meant to suggest that the US dollar amounts referred to above could be or could have been converted into pounds sterling at any particular rate indicated or any other rate.

xi OVERVIEW This summary highlights selected information contained elsewhere in this Offering Memorandum and does not contain all of the information that you should consider before investing in the Notes. The following summary should be read in conjunction with and is qualified in its entirety by the more detailed information included elsewhere in this Offering Memorandum. You should carefully read the entire Offering Memorandum to understand our business, the nature and terms of the Notes and the tax and other considerations which are important to your decision to invest in the Notes, including the more detailed information in the financial information and the related notes included elsewhere in this Offering Memorandum, before making an investment decision. Please see the section entitled “Risk Factors” for factors that you should consider before investing in the Notes and the section entitled “Forward-looking Statements” for information relating to the statements contained in this Offering Memorandum that are not historical facts.

Unless the context otherwise requires, all references herein to “we”, “our”, “ours”, “us”, and “the Group” are to the Company and its consolidated subsidiaries.

Our Group Since our inception in 1981 as a Texas-based designer and fabricator of modular plant, we have grown to become a FTSE 100 company with operations in 29 countries. In over three decades of operations, we have developed a wide range of skills and capabilities, which we use to help hydrocarbon resource holders develop and unlock the value of new and existing oil and gas assets, both onshore and offshore. As of 30 August 2013, Petrofac Limited had a market capitalisation of US$7.4 billion. We have a broad global footprint across a number of high-growth countries and regions, and our operations are run out of seven main operating centres in Aberdeen, Sharjah, Woking, Chennai, Mumbai, Abu Dhabi and Kuala Lumpur. We had 18,565 employees in 24 offices and 14 training centres across 29 countries worldwide as of 30 June 2013. For the six months ended 30 June 2013, the United Kingdom accounted for 27% of our revenue, while Algeria, Turkmenistan, Malaysia, UAE, Iraq, Kuwait and Mexico accounted for 13%, 12%, 10%, 7%, 7%, 5% and 4% of our revenue, respectively. For the year ended 31 December 2012, Turkmenistan accounted for 27% of our revenue and the United Kingdom accounted for 19% of our revenue, while Algeria, the UAE, Malaysia, Kuwait and Qatar accounted for 14%, 13%, 7%, 5%, and 4% of our revenue, respectively.

The following table sets forth our revenue, EBITDA, operating profit and profit attributable to Petrofac Limited shareholders for the periods indicated: Six Months Ended 30 June Year Ended 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) (US$ millions) Revenue ...... 2,794 3,187 6,324 5,801 4,354 EBITDA(2)(3) ...... 405 455 888 760 634 Operating profit(2)(4) ...... 295 412 758 680 539 Profit attributable to Petrofac Limited shareholders(5) ...... 243 326 632 540 433 (1) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement on such line items. (2) Unaudited. (3) EBITDA represents profit before tax adjusted for finance income, finance costs, depreciation, amortisation and impairment, as well as exceptional items such as the gain on the EnQuest demerger in 2010. (4) Operating profit represents profit before tax adjusted for finance income and finance costs as well as exceptional items such as the gain on the EnQuest demerger in 2010. (5) For 2010, profit attributable to Petrofac Limited shareholders excludes the gain on the EnQuest demerger of US$125 million.

Backlog increased to US$14.3 billion at 30 June 2013, having remained broadly steady over the last three years, at US$11.8 billion at the end of 2012, US$10.8 billion at the end of 2011 and US$11.7 billion at the end of 2010.

1 training personnel and integrating our spectrum of technical skills to support customers in developing their hydrocarbon resources. We are organised into two divisions: Engineering, Construction, Operations & Maintenance (“ECOM”) and Integrated Energy Services (“IES”), which together operate through seven service lines that report under four reporting segments.

Through the ECOM division, which is split into three reporting segments, we design and build oil and gas facilities and operate, manage and maintain them on behalf of our customers. The IES division, which is a single reporting segment, leverages our capabilities to provide integrated services to oil and gas resource holders.

For the six months ended 30 June 2013, the ECOM division accounted for 85% of our revenue, 69% of our EBITDA, 79% of our operating profit and 81% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, the ECOM division accounted for 89% of our revenue, 78% of our EBITDA, 83% of our operating profit and 86% of our profit attributable to Petrofac Limited shareholders. ECOM operations are split into three distinct reporting segments which are focused predominately on markets in the Middle East, the United Kingdom Continental Shelf (“UKCS”), Africa and the Commonwealth of Independent States (“CIS”): • Onshore Engineering & Construction (“OEC”) delivers onshore EPC projects. For the six months ended 30 June 2013, OEC accounted for 56% of our revenue, 59% of our EBITDA, 70% of our operating profit and 74% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, OEC accounted for 64% of our revenue, 64% of our EBITDA, 69% of our operating profit and 73% of our profit attributable to Petrofac Limited shareholders. • Offshore Projects & Operations (“OPO”) specialises in onshore and offshore operations and maintenance and brownfield modification projects and, through the Offshore Capital Projects (“OCP”) service line, specialises in providing offshore engineering, procurement, installation and commissioning (“EPIC”) services for greenfield projects. For the six months ended 30 June 2013, OPO accounted for 23% of our revenue, 8% of our EBITDA, 7% of our operating profit and 5% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, OPO accounted for 21% of our revenue, 10% of our EBITDA, 10% of our operating profit and 9% of our profit attributable to Petrofac Limited shareholders. • Engineering & Consulting Services (“ECS”) delivers early-stage engineering studies, including conceptual and front-end engineering and design (“FEED”) work across onshore and offshore oil and gas fields. For the six months ended 30 June 2013, ECS accounted for 6% of our revenue, 2% of our EBITDA, 2% of our operating profit and 3% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, ECS accounted for 4% of our revenue, 4% of our EBITDA, 4% of our operating profit and 4% of profit attributable to Petrofac Limited shareholders.

For the six months ended 30 June 2013, the IES division accounted for 15% of our revenue, 31% of our EBITDA, 21% of our operating profit and 19% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, our IES division accounted for 11% of our revenue, 22% of our EBITDA, 17% of our operating profit and 14% of our profit attributable to Petrofac Limited shareholders. IES was launched in 2011 as a single reporting segment and helps customers develop their resources either through the development of new fields or by enhancing production from mature reservoirs. The segment has three distinct but integrated service lines: • Developments develops, operates and maintains greenfield projects for resource holders. We will often co- invest in the development and receive returns based upon our performance; • Production Solutions improves production, operational efficiency and recovery from customers’ mature fields, which may involve investment in these field developments; and • Training Services develops and manages capability plans for customers and builds and operates training facilities. In 2012, Training Services managed 14 facilities in seven countries and delivered more than 200,000 “delegate days”, or days in which an individual was present at training.

2 Competitive Strengths We believe that the following are our key strengths:

Successful Track Record in an Attractive Market We have a successful track record over three decades, reflecting our rigorous approach to risk identification and mitigation from bid to project completion. Throughout the course of our history, we have managed increasingly larger and more complex projects and established a successful track record of on time and within cost budget delivery. Furthermore, we are one of the largest European oilfield services companies. With a market capitalisation of US$7.4 billion as of 30 August 2013, we are the third largest European listed oilfield services company by market capitalisation and our profit margin of 8.7% for the six months ended 30 June 2013 (10% for the year ended 31 December 2012) was one of the highest within this peer group. We had a backlog of US$11.8 billion as of 31 December 2012 increasing to US$14.3 billion as of 30 June 2013, which reduced slightly to US$14.0 billion as of 31 August 2013.

Our strong track record is partly due to an attractive market with increasing investments in oil and gas infrastructure and operations. The IEA estimates that there will be approximately US$19 trillion of capital expenditure in oil and gas infrastructure between 2012 and 2035, resulting from an expected increase in energy demand by over one-third in that period, or 1.2% per year on average from 2011 to 2035. Fossil fuels are expected to remain the main means of satisfying this global energy demand, according to the IEA. Of the investments in this period, approximately 50% are expected to be in the core markets in which we operate, including the UKCS, Middle East, Africa, the CIS and the Asia Pacific region. Furthermore, operational expenditures are expected to increase, as the average cost per barrel of developing, operating and maintaining new fields, often in remote or harsh environments, is likely to increase over time, while the cost per barrel of maintaining producing fields is likely to increase as such fields mature and production declines. Our addressable market is a small proportion of the total expenditure in the industry, and we expect that the key drivers of capital and operational expenditure should ensure that demand for our services will remain strong in the long-term.

Business Line Diversification through Innovative Business Models We have developed a geographically diverse portfolio and seek to continue our move away from our concentration in a limited number of regions, thereby enhancing our business profile. Furthermore, we have diversified our contractual offerings through our IES division, which provides integrated service contracts of a longer duration than the typical EPC contract, in particular through our expansion into risk service contracts (“RSCs”) and production enhancement contracts (“PECs”), the latter of which can last up to 25 years or longer.

According to the IEA, national oil companies’ (“NOCs”) share of global oil production is expected to increase over the next decade, driven by an increased desire by countries to maintain sovereignty over their hydrocarbon resources and increased technical capabilities and operating experience within NOCs meaning they no longer need to rely on international oil companies (“IOCs”) to the same extent. Our greenfield development offering through the use of RSCs and our brownfield production enhancement offering through the use of PECs do not require the resource holder to hand over ownership of reserves, making it appealing to NOCs who may be reluctant to do so. By delivering projects on a service basis, with contract terms that incentivise us to deliver the project on time and within budget or to continue to increase the production of a field, we are aligned with the interests of the resource holder. This alignment can be cemented further through our ability to invest in the projects and, through Training Services, to train and develop the workforce to build, maintain and operate the infrastructure going forward. As such, by working with us, NOCs are able to access our extensive engineering, project management, delivery and operating experience to develop or improve recovery from resources which they otherwise might not have been able to, while at the same time retaining full ownership of the underlying reserves and developing the local economy and workforce in the process.

Strong Long-term Relationships Throughout our development, we have sought to create and maintain a number of strong long-term relationships with strategic customers and partners, often through our Directors, Senior Management and other employees over the course of their careers with us. These relationships include NOCs such as Abu Dhabi Company for Onshore Oil Operations (“ADCO”), Kuwait Oil Company (“KOC”), Petróleos Mexicanos (“Pemex”), Petroliam Nasional Berhad (“Petronas”), Saudi Arabian Oil Company (“Saudi Aramco”); IOCs such as BP, Royal Dutch Shell (“Shell”) and Total; and other strategic partners including Schlumberger Limited (“Schlumberger”) and

3 SapuraKencana Petroleum Berhad (“SapuraKencana”). Our long-term relationships with customers have allowed us to gain a strong understanding of their needs and to become a trusted partner for their customised solutions.

Good Revenue Visibility Our order backlog provides us with good revenue visibility on a forward-looking basis as it is a measure of the potential future revenue of the business. We have consistently had strong backlog, with backlog of US$14.0 billion as of 31 August 2013, US$14.3 billion as of 30 June 2013, US$11.8 billion at the end of 2012, US$10.8 billion at the end of 2011, and US$11.7 billion at the end of 2010. Within these totals, IES backlog grew strongly to US$1.6 billion in 2011 after securing the Berantai RSC and Mexico PECs, and in 2012 the IES backlog grew to US$3.0 billion after we were awarded the Pánuco and Arenque PECs by Pemex and the contract for the charter of a mobile offshore production unit for the Block PM304 development in Malaysia. In the six months ended 30 June 2013, IES backlog grew to US$3.3 billion. The significant increase in our backlog during the six months ended 30 June 2013 has been largely driven by new order intake in the OEC segment, in particular the Upper Zakum, UZ750 field development, the Bab gas compression and the Bab Habshan 1 projects in Abu Dhabi and an increase in our economic interest in Petrofac Emirates.

Strong EBITDA Performance Historically, we have had strong cash flow generating capability, with a net cash position throughout 2012, 2011 and 2010. Whilst the ECOM division can show significant volatility in working capital, reflecting the phasing of EPC contract advances and other EPC receipts and payments, over time the division generates significant operating cash inflow from its portfolio of EPC and other contracts. For the six months ended 30 June 2013, ECOM EBITDA was US$262 million and for 2012, 2011 and 2010, ECOM EBITDA was US$711 million, US$687 million and US$525 million, respectively. For the six months ended 30 June 2013, IES EBITDA was US$116 million and for the years ended 31 December 2012, 2011 and 2010, IES EBITDA was US$196 million, US$89 million and US$127 million, respectively. Through IES, we invest in RSCs, production sharing contracts (“PSCs”) and PECs in countries such as Malaysia, Mexico, Romania and the United Kingdom. Our increased investments in IES caused our net cash (including unamortised debt acquisition costs) to decrease from US$1,495 million at the end of 2011 to US$265 million at the end of 2012. As of 30 June 2013, we had net debt (including unamortised debt acquisition costs) of US$370 million, with the cash outflow over the first six months of the year being predominately due to movements in working capital of US$485 million in our OEC and IES businesses (the result in part of timing differences on OEC lump-sum contracts in the first half of 2013 compared with the first half of 2012), and capital expenditure of US$201 million mainly in relation to IES projects. We expect to remain in a net debt position in the medium term, driven by the ongoing deployment of cash on IES projects and initial investment in our offshore strategy. However, as our IES portfolio of assets and EPIC strategy mature beyond the initial project investment phase, they are also expected to become increasingly cash generative.

Experienced Management Team We are led by a highly experienced executive team, with extensive skills developed across their fields of expertise. Ayman Asfari, our Group Chief Executive, was instrumental in founding us in our current form over 20 years ago. Our Directors, Senior Management and employees have significant interests in our equity, helping to ensure that our Directors, Senior Management and employees’ interests are aligned with those of our shareholders. Furthermore, our Senior Management has more than 350 years of combined experience in the oil and gas industry and has held management positions either at our Group or at other leading oil and gas companies such as AMEC plc (“AMEC”), BP, ConocoPhillips and Halliburton. Our market leading position, successful operating performance, financial performance, track record and strong relationships are all evidence of the strength of our Directors and Senior Management.

Business Strategy We aim to leverage the broad range of skills and capabilities we have developed during our more than three decades in operation to achieve our vision of being the world’s most admired oilfield service company. We have three main strategies to deliver this goal:

4 this will help us to create fresh opportunities and make us more resilient to challenges in individual regions of the world, ensuring that our portfolio remains balanced and robust. We implement this strategy through selecting those geographies that have substantial hydrocarbon reserves and which will allow us to transact business safely and responsibly. We focus in particular on those regions where we believe our mix of innovative contract options, preference for delivering services with local partners and ability to train and develop local workforces make us particularly effective and differentiate us from our competitors. This approach allowed us to become one of the first foreign companies in more than 70 years to operate a Mexican oilfield, when the state-owned Pemex awarded us a 25-year integrated production service contract for the Magallanes and Santuario blocks in Tabasco State in August 2011. Furthermore in 2012 we built on our presence in West Africa and Saudi Arabia. In November 2012, we signed a strategic alliance with Bowleven, an Africa-focused gas company, for a proposed development of the Etinde Permit in offshore Cameroon. In July 2012, in Saudi Arabia, we won two EPC contracts for Phase II of the petrochemical expansion project for Petro Rabigh, and in December 2012 Saudi Aramco awarded us two further EPC contracts for the Jazan refinery and terminal project. We intend to continue to grow our activities in recently-entered countries and move into new markets in the CIS, East Africa and South East Asia.

Developing our EPIC Business Offshore Another strategic priority is to combine our EPC capabilities with our offshore operational skills to enhance our offshore EPIC service offering. We have been operating offshore oil and gas fields since 2002, and in 2012 we created a new service line, OCP, to help achieve our EPIC goals. In the short term, we intend to focus our OCP capabilities in shallow waters in South East Asia, the UAE and the Caspian Sea, with the longer term intention of targeting developments in deeper waters in regions such as the Gulf of Mexico and West Africa. In April 2013, we were awarded a contract for US$500 million in the Satah Al Razboot package 3 (“Sarb 3”) project in the UAE.

Offshore oil and gas production is expected to play an increasing role in the oil and gas sector, especially deeper water production, with the offshore market expected to require capital expenditure of US$100 billion in 2013 forecasted to grow to US$150 billion by 2020, according to Douglas-Westwood. The deeper water activities (subsea, umbilicals, risers and flowlines (“SURF”) and pipelines) are expected to provide the strongest growth potential in this time period of over 15% per year in terms of capital expenditure, while competition has consolidated within this high-end offshore segment with just three main EPIC providers, Saipem S.p.A (“Saipem”), Technip S.A. (“Technip”) and Subsea 7 S.A. (“Subsea 7”). To address this opportunity and expand our OCP offering, we are implementing a plan to build a high quality OCP team which can deliver offshore projects in both shallow and deep waters. In February 2013, we announced our intention to invest up to US$1 billion over the next five years in building our own installation capability, underpinned by one high specification, multi-function derrick lay vessel. Our aspiration through this investment in both assets and people is to become a top-tier offshore EPIC service provider, thus leveraging our considerable offshore operational experience, project management and engineering skills and further diversifying our geographic and service offering portfolio.

Delivering our IES Offering We launched our IES division in June 2011 with the goal of leveraging all of our capabilities to support customers in developing their hydrocarbon resources. We have the capability to develop and manage oil and gas fields by deploying a range and depth of technical knowledge and skills which we believe we can leverage to support customers, particularly NOCs and small explorers seeking support in managing and developing their assets under flexible commercial models that allow them to retain ownership of their reserves. As NOCs often wish to retain control of their own reserves and to develop local capabilities and supply chains, our flexible model positions us to capitalise on the NOCs’ growing share of global oil production. IES projects cover upstream developments, both greenfield and brownfield, and related energy infrastructure projects, which often include investments of our capital, such as investment in and deployment of floating production units. Our global portfolio of projects includes the Arenque, Magallanes, Pánuco and Santuario PECs with Pemex, the offshore Berantai project in Malaysia, the Ticleni oilfield in Romania and in the Greater Stella Area in the North Sea, where we will have a 20% production share when we achieve first oil. We intend to continue to broaden this portfolio through developing the capabilities that allow us to meet customer needs, and will continue to consider options such as investment in energy infrastructure projects. Increased upstream activity has required that we expand in areas such as specialist subsurface engineering, drilling and asset management; as a result, we have established a technical centre in our UK office in Woking, and we are setting up another technical centre in

5 Delhi, India. Furthermore, NOCs often require that we use and develop local staff, and so we are continuing to expand our technical skills training capability offered by Training Services which we can deploy to develop local workforces and increase competence.

Recent Developments On 19 September 2013, a consortium consisting of the Group, Linde AG of Germany and GS Engineering & Construction Corp. was engaged by KLPE LLP, to provide services to develop its integrated petrochemicals complex and infrastructure (“IPCI”) project in Kazakhstan. The first phase of the contract is valued at US$77 million, of which our share is approximately US$21 million. We will lead the consortium for the execution of the ICPI project. Subject to satisfactory execution of the first phase, a second phase, valued at over US$3.5 billion, is contemplated, to construct a polyethylene plant. The eventual scope for the IPCI project is expected to include the engineering, procurement, construction and commissioning of a gas plant, ethane cracker, gas pipelines, polyethylene plants and associated utilities and offsites in Kazakhstan.

On 12 September 2013, we were awarded a US$120 million contract with Petronas, the Malaysian national oil company, for the operation and management of two high-specification training facilities that we are building to support Petronas’ workforce capability enhancement programme. Under the agreement, we will undertake the operation and management of the facilities for the next five years with an option to extend for a further two years.

On 11 September 2013, Petrofac Emirates, our Abu Dhabi based joint venture, received an advance payment of approximately US$290 million in respect of the Upper Zakum UZ750 field development project in Abu Dhabi.

On 22 August 2013, we were awarded a second contract by Gazprom Neft Badra B.V. on the Badra Oil Field in Iraq, worth US$95 million over three years. The contract was awarded to our OPO business to provide maintenance engineering, maintenance execution and support services. The award builds on a previous contract to carry out the EPC work on the first phase of the field’s processing facilities.

On 24 July 2013, our President and Executive Director Maroun Semaan announced his decision to retire at the end the year and to step down from the Board of Directors, after having worked at Petrofac for 22 years. Kathleen Hogenson has been appointed to the Board of Directors as a Non-executive Director with effect from 1 August 2013. Ms. Hogenson, President and CEO of her own US-based company Zone Energy LLC, has 30 years’ experience in the oil and gas industry, with particular expertise in reservoir management and subsurface engineering. Ms. Hogenson has joined our Audit, Nominations and Board Risk Committees.

With effect from 1 January 2013, we agreed to increase our economic interest in Petrofac Emirates, our Abu Dhabi based joint venture with Mubadala Petroleum Services Company LLC (“Mubadala Petroleum”), to 75%. Mubadala Petroleum sold its shares in Petrofac Emirates to Nama Project Services LLC (“Nama Project Services”). Nama Project Services is an affiliate of Nama Development Enterprises, a leading local service provider to the energy industry across the UAE. Nama Project Services will hold a 25% economic interest in Petrofac Emirates.

On 7 June 2013, we signed a Memorandum of Understanding (“MOU”) with KazMunaiGas Exploration Production JSC of Kazakhstan. The MOU allows the parties to explore opportunities to improve the efficiency of oil production and increase production from the mature Emba fields of KMG EP’s subsidiary EmbaMunaiGas JSC. Under the terms of the MOU, we intend to evaluate the Emba fields and to submit an offer for the long term improvement of the management and production in selected Emba fields in order to progress a potential PEC.

In January 2013, following the terrorist attack at the In Amenas natural gas site in Algeria, at the request of our customer, we evacuated our staff on a temporary basis from the In Salah southern fields development in that country. We have made progress at the site during 2013 and we are currently finalising arrangements with our client for further mobilisation of resources in the near future. This evacuation and delayed remobilisation will result in the deferral of significant project revenue from 2013 to 2014 but does not impact our expectations for profit margins over the life of the project.

As of 31 August 2013, we had a net debt position of US$602 million consisting of US$939 million utilised under the Revolving Credit Facility, US$148 million of project financing for the Berantai floating production, storage and offloading vessel (“FPSO”), bank overdrafts of US$26 million and cash and short-term deposits of US$511 million.

6 Risk Factors Investing in the Notes involves substantial risks. You should consider carefully all the information in this Offering Memorandum and, in particular, you should evaluate the specific risk factors set out in the “Risk Factors” section in this Offering Memorandum before making a decision whether to invest in the Notes. You should note that the risks described in this Offering Memorandum are not the only risks we face. We have described only those risks we consider to be material. However, there may be additional risks that we currently consider immaterial or of which we are currently unaware which are or may become material.

The Company The Company, Petrofac Limited, is a public limited company incorporated with limited liability under the laws of Jersey. Our registered address and the business address of each of our directors is Ogier House, The Esplanade, St Helier, Jersey JE4 9WG and our telephone number is +44 1534 504000. The register of members of the Company is maintained by Capita Registrars (Jersey) Limited and is located at 12 Castle Street, St Helier, Jersey JE2 3RT.

The Company is authorised to issue up to 750,000,000 ordinary shares of US$0.02 each. As of 26 September 2013 (being the latest practicable date prior to the publication of this document), we had an issued share capital of US$7 million comprised of 345,912,747 ordinary shares with a par value of US$0.02 per share, with each share being issued and fully paid.

The secretary of the Company is Ogier Corporate Services (Jersey) Limited which is regulated pursuant to the Financial Services (Jersey Law) 1998 to carry on trust company business including acting as company secretary. The registered office of Ogier Corporate Services (Jersey) Limited is Ogier House, The Esplanade, St Helier, Jersey JE4 9WG.

Summary Financial Statements Consolidated Income Statement

Six Months Ended 30 June Year Ended 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Revenue ...... 2,794 3,187 6,324 5,801 4,354 Cost of sales ...... (2,292) (2,655) (5,244) (4,841) (3,595) Gross profit ...... 502 532 1,080 960 759 Selling, general and administration expenses ...... (217) (176) (359) (283) (222) Gain on EnQuest demerger ...... ————125 Other income ...... 8 46 65 12 5 Other expenses ...... (8) (9) (20) (5) (4) Profit from operations before tax and finance (costs)/income ...... 285 393 766 684 663 Finance costs ...... (6) (2) (5) (7) (5) Finance income ...... 11 3 12 8 10 Share of profits/(losses) of associates/joint ventures ...... 10 19 (8) (4) — Profit before tax ...... 300 413 765 681 668 Income tax expense ...... (58) (89) (135) (141) (110) Profit for the year ...... 242 324 630 540 558 Profit for the year attributable to: Petrofac Limited shareholders ...... 243 326 632 540 558 Non-controlling interests ...... (1) (2) (2) — 242 324 630 540 558

7 Summary Consolidated Statement of Financial Position

As of 30 June As of 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Total non-current assets ...... 2,189 1,555 2,001 1,156 625 Total current assets ...... 3,499 3,112 3,331 3,736 2,976 of which, cash and short-term deposits ...... 538 790 614 1,572 1,063 Total assets ...... 5,688 4,667 5,332 4,892 3,601 Equity attributable to Petrofac Limited shareholders .... 1,600 1,269 1,549 1,112 776 Non-controlling interests ...... 51133 Total equity ...... 1,605 1,270 1,550 1,115 779 Total non-current liabilities ...... 1,049 182 543 160 145 Of which, interest-bearing loans and borrowings . . 835 2 292 16 40 Total current liabilities ...... 3,034 3,215 3,239 3,617 2,677 Of which, interest-bearing loans and borrowings . . 73 65 57 61 47 Total liabilities ...... 4,083 3,397 3,782 3,777 2,822 Total equity and liabilities ...... 5,688 4,667 5,332 4,892 3,601

Summary Consolidated Statement of Cash Flows

Six Months Ended 30 June Year Ended 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Net cash flows (used in)/from operating activities ...... (209) (401) (401) 1,263 106 Net cash flows used in investing activities ...... (196) (155) (544) (523) (254) Net cash flows from/(used in) financing activities ...... 366 (215) (36) (227) (201) Cash and cash equivalents at period end ...... 485 753 557 1,535 1,034 (1) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement on such line items.

8 Segmental Information The following table shows the breakdown of revenue, profit attributable to Petrofac Limited shareholders and profit margin by reporting segment for the periods indicated:

Profit Attributable to Petrofac Revenue Shareholders(1) Profit Margin(2) Six Months Six Months Six Months Ended Year Ended Ended Year Ended Ended Year Ended 30 June 31 December 30 June 31 December 30 June 31 December 2013 2012(3) 2012 2011 2010(4) 2013 2012(3) 2012 2011 2010(4) 2013 2012(3) 2012 2011 2010(4) (unaudited) (audited) (unaudited) (audited) (unaudited) (audited) (US$ millions) (percent) Onshore Engineering & Construction ...... 1,610 2,333 4,358 4,146 3,254 171 251 479 463 373 10.6 10.8 11.0 11.2 11.5 Offshore Projects & Operations ...... 670 6611,403 1,252 722 12 31 61 44 17 1.8 4.7 4.3 3.5 2.4 Engineering & Consulting Services ...... 180 103 248 208 173 6 5 29 31 21 3.3 4.9 11.7 14.8 12.2 Integrated Energy Services ...... 419 318 719 519 384 43 64 89 22 38 10.3 20.1 12.4 4.4 9.9 Corporate, consolidation & elimination ...... (85) (228) (404) (324) (179) 11 (25) (26) (20) (16) Group ...... 2,794 3,187 6,324 5,801 4,354 243 326 632 540 433 8.7 10.2 10.0 9.3 9.9

(1) For 2010, profit attributable to Petrofac Limited shareholders excludes US$125 million from the gain on the EnQuest demerger. (2) Profit margin is profit attributable to Petrofac Limited shareholders represented as a percentage of revenue. (3) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement of such line items. (4) The segmental comparative 2010 figures were restated in our 2011 Consolidated Financial Statements to reflect our revised organisational structure. See “Operating and Financial Review—Basis of Preparation of Financial Information”.

Other Non-IFRS Financial Information EBITDA and Operating Profit The following table shows EBITDA and operating profit by reporting segment for the periods indicated

EBITDA(1) Operating Profit(1) Six Months Six Months Ended Year Ended Ended Year Ended 30 June 31 December 30 June 31 December 2013 2012(2) 2012 2011 2010 2013 2012(2) 2012 2011 2010 (unaudited) (unaudited) (unaudited) (unaudited) (US$ millions) Onshore Engineering & Construction ...... 224 318 580 585 472 190 299 540 554 438 Offshore Projects & Operations ...... 29 44 95 62 27 20 42 79 57 24 Engineering & Consulting Services ...... 9 7 36 40 26 6 4 30 33 20 Integrated Energy Services ...... 116 110 196 89 128 57 90 133 53 74 Corporate, consolidation & elimination ..... 27 (24) (19) (16) (19) 22 (23) (24) (17) (17) Group ...... 405 455 888 760 634 295 412 758 680 539

9 The following table sets out the reconciliation of EBITDA and operating profit to profit before tax by reporting segment for the periods indicated:

Six Months Ended 30 June 2013 Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 197 19 6 64 (5) 19 300 Finance income ...... (7) — — (10) (10) 16 (11) Finance costs ...... — 1 — 3 10 (8) 6 Operating profit ...... 190 20 6 57 (5) 27 295 Depreciation, amortisation and write- offs ...... 34 9 3 59 6 (1) 110 EBITDA ...... 224 29 9 116 1 26 405

Six Months Ended 30 June 2012(2) Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 303 42 4 88 (3) (21) 413 Finance income ...... (4) — — — (3) 4 (3) Finance costs ...... — — — 2 2 (2) 2 Operating profit ...... 299 42 4 90 (4) (19) 412 Depreciation, amortisation and write- offs ...... 19 2 3 20 — (1) 43 EBITDA ...... 318 44 7 110 (4) (20) 455

Year Ended 31 December 2012 Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 548 79 31 136 5 (34) 765 Finance income ...... (8) — (1) (7) (9) 13 (12) Finance costs ...... — — — 4 6 (5) 5 Gain on the EnQuest demerger ...... — — — — — — — Operating profit ...... 540 79 30 133 2 (26) 758 Amortisation and impairment ...... — 1 1 8 1 — 11 Depreciation ...... 40 15 5 55 6 (2) 119 EBITDA ...... 580 95 36 196 9 (28) 888

10 Year Ended 31 December 2011 Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 561 56 33 50 (10) (9) 681 Finance income ...... (9) — — — (2) 3 (8) Finance costs ...... 2 1 — 3 3 (2) 7 Gain on the EnQuest demerger ...... — — — — — — — Operating profit ...... 554 57 33 53 (9) (8) 680 Amortisation and impairment ...... — 1 1 1 — — 3 Depreciation ...... 31 4 6 35 1 — 77 EBITDA ...... 585 62 40 89 (8) (8) 760

Year Ended 31 December 2010(3) Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 448 24 20 195 (15) (3) 669 Finance income ...... (10) — — — (3) 3 (10) Finance costs ...... — — — 4 4 (3) 5 Gain on the EnQuest demerger ...... — — — (125) — — (125) Operating profit ...... 438 24 20 74 (14) (3) 539 Amortisation and impairment ...... — 1 1 — — — 2 Depreciation ...... 34 2 5 53 — (1) 93 EBITDA ...... 472 27 26 127 (14) (4) 634

(2) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement on such line items. (3) The segmental comparative 2010 figures were restated in our 2011 Consolidated Financial Statements to reflect our revised organisational structure. See “Operating and Financial Review—Basis of Preparation of Financial Information”.

Net Cash / (Debt) The following table shows net cash / (debt) for the periods indicated.

As of 30 June As of 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Cash and short-term deposits ...... 538 790 614 1,572 1,063 Revolving Credit Facility(2) ...... (720) — (303) — — Project Financing(3) ...... (148) — — — — Bank Overdrafts ...... (53) (37) (57) (37) (29) Interest bearing loans and borrowings(2) ...... — (33) — (43) (63) Net cash / (debt) ...... (383) 720 254 1,492 971

11 Consolidated Financial Statements for details, including the impact of the restatement on such line items. (2) The Revolving Credit Facility and interest bearing loans and borrowings balances exclude unamortised debt acquisition costs and effective interest rate adjustments. (3) Project Financing represents our share of a senior secured term loan facility entered into by our joint venture project, Berantai Floating Production Limited (“BFPL”). Our wholly owned subsidiary Petrofac Energy Developments Sdn Bhd (“PED”) owns a 51% share of BFPL. See “Operating and Financial Review— Liquidity and Capital Resources—Indebtedness—Project Financing”.

Backlog Our backlog as of 30 June 2013 was US$14.3 billion, US$11.8 billion as of 31 December 2012, US$10.8 billion as of 31 December 2011 and US$11.7 billion as of 31 December 2010. See “Presentation of Financial and Other Information—Non-IFRS Financial Information—Backlog”.

12 The Offering The following is a brief summary of certain terms of this Offering and may not contain all the information that is important to you. For additional information regarding the Notes and the Guarantees, please see “Description of Notes and Guarantees”. Issuer ...... Petrofac Limited. Guarantors ...... Petrofac International Ltd and Petrofac International (UAE) LLC. Notes ...... US$750 million aggregate principal amount of Senior Notes due 2018. Guarantees ...... The obligations of the Company under the Notes and the Fiscal Paying Agency Agreement governing the Notes will be irrevocably and unconditionally guaranteed on a joint and several basis by the Guarantors. Issue Date ...... 10October 2013. Issue Price ...... 99.627% plus accrued interest, if any, from 10 October 2013. Maturity Date ...... 10October 2018. Interest Rate ...... TheNotes will bear interest from the Issue Date at the rate of 3.400% per annum, payable semi-annually in arrears. Interest Payment Dates ...... Interest on the Notes will be paid semi-annually in arrears on 10 April and 10 October of each year commencing on 10 April 2014. Form and Denomination ...... TheCompany will issue the Notes on the Issue Date in global form in minimum denominations of US$2,000 and integral multiples of US$1,000 in excess thereof. Additional Amounts ...... The Company and the Guarantors will pay additional amounts in respect of any payments of interest or principal so that the amount you receive after any Relevant Taxing Jurisdiction (as defined in “Description of Notes and Guarantees”) withholding tax will equal the amount that you would have received if no withholding tax had been applicable, subject to some exceptions as described under “Description of Notes and Guarantees—Additional Amounts”. Optional Redemption ...... TheCompany or any Guarantor may redeem the Notes, in whole or in part, at the option of the Company or such Guarantor at any time and upon notice as described below, at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest thereon (excluding any portion of such payments of interest accrued as of the date of redemption) discounted to the date of redemption on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined in “Description of Notes and Guarantees”) plus 35 basis points, plus in each case accrued and unpaid interest to the date of redemption. Tax Redemption ...... If, due to certain changes in the tax law of a Relevant Taxing Jurisdiction (as defined in “Description of Notes and Guarantees”) occurring on or after the date of this Offering Memorandum (or after the date of succession or substitution in the case of any other jurisdiction in which a successor to, or substitute obligor of, the Company is organised or resident for tax purposes) the Company would be required to pay additional amounts as described under “Description of Notes and Guarantees—Additional Amounts”, the Company may redeem the Notes in whole but not in part at a redemption price equal to 100% of the principal amount of the Notes plus accrued interest and additional amounts, if any, to (but excluding) the redemption date.

13 Change of Control ...... IfaChange of Control Triggering Event (as defined in “Description of Notes and Guarantees”) occurs, the Issuer or the Guarantors may be required to repurchase the Notes at a purchase price equal to 101% of their aggregate principal amount, plus accrued and unpaid interest. See “Description of Notes and Guarantees—Change of Control Repurchase Event”.

Certain Covenants ...... The Company and the Guarantors have agreed to observe certain covenants with respect to the Notes, including a limitation that restricts the Issuer’s and its Restricted Subsidiaries’ (as defined in “Description of Notes and Guarantees”) ability to create or incur certain secured debt, enter into certain sale and leaseback transactions and a limitation that restricts the Issuer’s and the Guarantors’ ability to consolidate, merge or transfer all or substantially all of their assets. See “Description of Notes and Guarantees”.

Ranking of the Notes ...... The Notes will be unsecured and unsubordinated obligations of the Company and will rank pari passu among themselves and with all other present or future unsecured and unsubordinated obligations of the Company from time to time outstanding.

Ranking of the Guarantees ...... TheGuarantees are unsecured and unsubordinated obligations of the Guarantors and will rank pari passu with all of the other present or future unsecured and unsubordinated obligations of the Guarantors.

Use of Proceeds ...... It is anticipated that the net proceeds of the Offering will be approximately US$745 million. We intend to use the majority of the net proceeds from the Offering to reduce the amount outstanding under the Revolving Credit Facility and the rest for general corporate purposes. See “Use of Proceeds”.

Conflicts of Interest ...... Affiliates of certain of the Initial Purchasers are lenders under our Revolving Credit Facility. To the extent the proceeds of the Offering are used to repay indebtedness under our Revolving Credit Facility, such affiliates of the Initial Purchasers will receive a portion of the proceeds of the Notes.

Transfer Restrictions ...... The Notes and the Guarantees have not been and will not be registered under the Securities Act or the securities laws of any other jurisdiction. The Notes are subject to restrictions on transferability and resale. Please see “Notice to Investors”. Holders of the Notes will not have the benefit of any exchange or registration rights.

Risk Factors ...... See “Risk Factors” and the other information included in this Offering Memorandum for a discussion of the factors you should carefully consider before investing in the Notes.

Listing ...... Application has been made to list the Notes on the Official List of the Irish Stock Exchange and to trade the Notes on the Irish Stock Exchange’s Global Exchange Market.

Governing Law ...... The Fiscal and Paying Agency Agreement, the Notes and the Guarantees will be governed by English law.

Irish Listing Agent ...... Arthur Cox Listing Services Limited.

14 Fiscal Agent, Paying Agent and Transfer Agent ...... Citibank, N.A., London Branch.

Registrar ...... Citigroup Global Markets Deutschland AG.

Ratings ...... Itisexpected that the Notes will be rated BBB+ by S&P and Baa1 by Moody’s, subject to confirmation at closing. A rating is not a recommendation to buy, sell or hold securities and may be subject to revision, suspension or withdrawal at any time by the assigning rating organisation. Each of S&P and Moody’s (which each provide ratings in relation to the Group and the Notes) are established in the European Union and registered in accordance with Regulation (EU) No 1060/2009.

CUSIP

144A ...... 716473 AC7

Regulation S ...... G7052T AC5

ISIN

144A ...... US716473AC70

Regulation S ...... USG7052TAC56

15 RISK FACTORS

RISKS RELATING TO OUR BUSINESS Our future business performance depends on the renewals and extensions of existing contracts and the award of new contracts It is generally very difficult to predict whether and when we will be awarded contracts for the large-scale projects that we bid upon, 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, competition, availability of customer financing and governmental approvals. The costs associated with bidding for new contracts or for extensions in the scope of work or renewals of existing contracts can be significant as they are not usually recoverable from customers and may not necessarily result in the award of new contracts, or in the extension or renewal of an existing contract. We participate in a number of such bids each year and failure to win such bids may have a material adverse effect on our business, financial position and results of operations.

Furthermore, we have many long-standing relationships with customers, and any damage to these relationships, from performance-related issues or otherwise, could result in the failure to win new contracts or in a customer’s decision not to renew or extend existing contracts. Due to the size of many of our projects, the majority of our revenue in any year may be derived from a relatively small number of contracts. For the six months ended 30 June 2013, and in the years ended 31 December 2012, 2011 and 2010, our top ten contracts accounted for 58%, 69%, 67% and 63%, respectively, of our revenue, and the loss of any one major customer could have an adverse impact on our financial performance. In addition, the loss of a major customer would reduce the availability of repeat business from that customer, and could also damage our reputation. Such reputational loss could jeopardise our existing relationships with other customers or our ability to establish new customer relationships, which may have a material adverse effect on our business, financial position and results of operations.

Demand for our services is linked to the level of expenditure by the oil and gas industry and fluctuating prices of, and supply and demand for, crude oil, natural gas, oil products and chemicals Demand for the majority of our services is dependent on expenditure by the oil and gas industry for the exploration and development of and production from crude oil and natural gas reserves. The level of expenditure and activity is in turn driven largely by current and expected market prices, as well as supply and demand, for oil and gas, among other factors, which determine the capital and operating expenditure budgets of our principal customers. Prices of oil, natural gas, oil products and chemicals are affected by supply and demand, both globally and regionally and, moreover, prices for oil and gas can move independently from each other. Factors that influence supply and demand include operational issues, natural disasters, weather, political instability, conflicts, economic conditions, the rate of decline of existing reserves, changes in environmental legislation and regulations and actions by major oil exporting countries. Short-term increases in oil and gas prices alone may not result in an increase in demand for our services as customers often take a longer term view on future oil prices in deciding on whether to sanction major oil and gas projects, but a substantial or extended decline, or prolonged volatility, in oil or gas prices would be likely to cause a decline or delays in the demand for our services. Lower expenditure by the oil and gas industry may result in lower demand for our services, which may have a material adverse effect on our business, financial position and results of operations.

Furthermore, IES has entered into certain PSCs and has investments in producing fields. As a result, we are partly exposed to fluctuations in oil and gas prices and the diversity of our other operations may not protect us against such market price fluctuations. For example, our PSCs for projects on the Block PM304 development in Malaysia and the Chergui Gas Plant in Tunisia expose us to fluctuations in the prices of Brent Crude Oil and natural gas prices, respectively. Decreases in oil and gas prices could have a material negative impact on the IES division, which in turn may have a material adverse effect on our business, financial position and results of operations.

We may be unable to attract and retain sufficient skilled personnel to meet our operational requirements Demand for engineers, production operations personnel and other technical and management personnel is currently high worldwide and supply is limited. The availability of sufficiently skilled, experienced and capable personnel, particularly at a senior level, remains one of the most significant challenges facing the oil and gas services industry. This shortage is exacerbated by the ageing of the current skilled workforce which is not being fully replaced by younger entrants, as well as by an increasing reluctance of workers from Western Europe and

16 the United States 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 can work. The shortage of personnel may be potentially more acute where we are required by NOCs to use local workforces, which may be less experienced.

Our future growth, particularly the growth of IES and OCP, and our performance depend to a large extent on our continued ability to attract, retain, motivate and organise appropriately qualified personnel. Our ability to meet operational requirements and our future growth and profitability 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, particularly in areas where we are still developing internal skills, such as IES and the new OCP service line. If we are unable to attract sufficient numbers of skilled employees, or if the compensation costs associated with attracting and retaining employees increase significantly, it may have a material adverse effect on our business, financial position and results of operations.

We may be adversely affected by liquidity and financial counterparty risk We are exposed to liquidity risk arising from the need to finance our ongoing operations and growth. Global credit markets have been severely constrained in the past, and our ability to obtain financing may be reduced should similar conditions recur. Furthermore, the cost of obtaining future funding may also increase significantly over time. A downgrade of our credit ratings would also have a negative impact on our ability to obtain funding and could increase the cost of financing. If we are unable to obtain sufficient credit, either due to banking or capital market conditions generally, or due to factors specific to our business, we may not have sufficient cash to invest in new projects, particularly in OCP and IES, or meet on-going operational requirements, which may have a material adverse effect on our cash flows, business, financial position and results of operations.

In addition, we are exposed to counterparty risk on financial institutions with which we hold cash and maintain derivative positions. Should any such counterparties be unable to meet their obligations to us, it may have a material adverse effect on our cash flows, business, financial position and results of operations.

Our operations expose us to political and social instability, terrorism and acts of war or piracy Our international operations, particularly those in the Middle East, North and West Africa and the CIS, may be susceptible to political, social and economic instability and civil disturbances. Risks for operating in such areas include but are not limited to: • difficulties in collecting accounts receivable and longer collection times than usual; • 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; • limited access to certain geographies for periods of time; • exposure to expropriation; • lack of established legal systems; and • arbitrary or unpredictable tax rulings.

Any of the above factors could result in disruptions to our business, increased costs, loss of capital invested, liability for liquidated damages and reduce profits and future growth opportunities.

Social and civil unrest such as that which recently occurred in North Africa and the Middle East can and does affect our operations, cash flow generation and earnings. Potential developments that could impact our business include international sanctions, conflicts, such as war, acts of political or economic terrorism and acts of piracy on the high seas, as well as civil unrest and local security concerns that threaten the safe operation of facilities and the transport of products. In 2011 and 2012, for example, unrest in the region led to the evacuation of a site in Tunisia, resulting in temporary cessation of gas production at that site, which had a minor financial impact on our Group. In January 2013, following the terrorist attack at the In Amenas natural gas site in Algeria, at the request of our customer, we evacuated our staff on a temporary basis from the In Salah southern fields development in that country. We are currently finalising arrangements with our client for further mobilisation of

17 resources in the near future. This evacuation and delayed remobilisation will result in the deferral of significant project revenue from 2013 to 2014. If these and other such risks materialise, they could result in disruption to business activities, which may have a material adverse effect on our business, financial position and results of operations.

Ethical misconduct or breaches of applicable laws by our employees or those acting on our behalf could be damaging to our reputation and shareholder value Our Code of Conduct, which applies to all employees, defines our commitment to integrity, compliance with all applicable legal requirements, high ethical standards and the behaviours and actions we expect of our businesses and people wherever we operate. This code, which was revised in 2012 to incorporate best practices, is intended to guide the way we and our employees behave and do business. Incidents of ethical misconduct or non- compliance with applicable laws and regulations, including non-compliance with anti-bribery, anti-corruption and other applicable laws could be damaging to our reputation. Events of non-compliance may cause us to be subject to significant fines, call into question the integrity of our operations, result in damage to our reputation and have a material adverse effect on our business, financial position and results of operations.

We operate in many jurisdictions and as a result are subject to a wide variety of laws and regulations, non- compliance with which could cause us reputational damage and expose us to substantial fines and penalties We operate globally and it is expected that the geographical expansion of our business, which is part of our strategy, will take us into new locations. We currently operate our businesses and market our services in 29 countries. Through our international presence, we are subject to increased risk from a number of legal, economic and market factors which are beyond our control and which may have a material adverse effect on our ability to provide services in those areas, or to continue to expand our business geographically. Such risks include: • reversal of current policies (including favourable tax and lending policies) encouraging foreign investment or foreign trade by the governments of countries in which we operate; • 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; • difficulty in obtaining visas for personnel; • the requirement in some countries that business be conducted through local agents; and • expropriation of assets.

The occurrence of any of these events may have a material adverse effect on our financial performance and position and adversely affect the value of our assets. In addition, the geographical spread of our 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 our principal locations can make it more difficult to implement and impress upon local workforces our policies on matters such as health and safety and can present challenges in the supervision of our sub-contractors. Failure to deliver consistently high standards across all of our fields of operations could create risks for us, including reputational risk, and may have a material adverse effect on our business, financial position and results of operations.

We are dependent on a small number of large contracts at any given time Due to the size of many of our projects, the majority of our revenue in any year may be derived from a relatively small number of contracts. For example, for the six months ended 30 June 2013 and the year ended 31 December 2012, our ten largest contracts represented 58% and 69% of our revenue, respectively. Consequently, should any one of those contracts prove less profitable for us than expected, or be loss making, revenues may decline significantly, which may have a material adverse effect on our financial performance and condition. In addition, we may have multiple projects for the same customer and therefore one customer may comprise a significant percentage of our backlog or of our revenue for any given period.

18 Part of our strategy is to bid for integrated projects, which involve several different parts of the Group and to leverage existing relationships to offer services from our other service lines. If this strategy results in our portfolio becoming more concentrated on fewer contracts or fewer customers, our exposure to individual contract risks will increase. Loss of a contract for a customer of more than one of our service lines or worse than expected performance under such a contract may have a knock-on impact on contracts for the same customer in other service lines, and may thereby have a correspondingly more material adverse effect on our cash flows, business, financial position and results of operations.

Investments we make may not generate profit or business synergy and may decline in value From time to time, principally through our IES division, we contribute financial capital to projects and we expect to do so increasingly as IES grows. However, there can be no assurance that any investment will generate the expected return or provide the expected business synergies for the other parts of the Group. If the fair value of any of our investments declines, we may be forced to write down the recorded value of our investment. We may also be required to make additional cash investments in the future to fund the operating or capital expenses of our investments. Furthermore, some of the investments are subject to contractual and other restrictions on transfer and we may not be able to dispose of them at attractive prices or in a timely manner. If we have investments which do not generate profit or business synergies or which decline in value or cannot be remarketed, such events may have a material adverse effect on our cash flows, business, financial position and results of operations.

We conduct our operations within a strict health and safety regime. Failure to comply with the relevant regulations could adversely affect our reputation and future revenue We are subject to strict health and safety regimes governing the full spectrum of our operations. We may be exposed to fines, penalties or prosecutions by governmental authorities in respect of non-compliance with applicable regulations, which may have a material adverse effect on our ability to operate. Our operations are associated with the emission of “greenhouse gases”. Ongoing international negotiations which aim to limit greenhouse gas emissions may result in the introduction of new regulations, which may increase costs that affect our day-to-day operations and may also have a material adverse effect on our business, financial position and results of operations.

Our OPO service line manages the operation of installations in the UKCS on behalf of a number of customers which own the installations and have been granted a production licence by the Department of Energy & Climate Change. As part of our management role in assisting certain customers to discharge responsibilities under their licences, we take on full responsibility for the safe management of these offshore installations. In such cases, under the applicable offshore safety regulations, we are considered to be acting as Duty Holder in performing this role. We are responsible, amongst other matters, for preparing and updating a safety case, demonstrating that we have considered all the possible hazards that may occur on the installation, their likelihood of occurrence and how we have 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 (“HSE”). Improvement notices or prohibition notices may be filed or prosecutions may be brought against us by the HSE for our failure to comply with these regulations. Furthermore, we are subject to the health and safety regimes of other jurisdictions in which we operate, such as Malaysia, Mexico, Romania and the UAE. A prosecution in the area of health and safety could expose us to fines or penalties and/or adversely affect our reputation, including, in particular, our reputation as an operator. This, in turn, may adversely affect our ability to operate and our ability to generate new business, which may have a material adverse effect on our business, financial position and results of operations.

We could be subject to substantial liability claims due to the hazardous nature of our business Many of our services are carried out in hazardous environments, such as development and production installations, and we both design and construct large industrial facilities in which a systems failure could be catastrophic. The health, safety, security and environmental risks to which we are potentially exposed cover a wide spectrum, given the geographic range, operational diversity and technical complexity of our operations. We have operations that include drilling for and producing oil and gas, working with hazardous materials, transport and shipping of hydrocarbons, and refining in difficult geographies or climate zones, as well as environmentally sensitive regions, such as maritime environments. This exposes us to the risk, among others, of major process safety incidents, effects of natural disasters, social unrest and personal health and safety and crime. If a major risk materialises, such as an explosion or hydrocarbon spill, this could result in injuries, loss of life, environmental harm, loss of licences that enable us to operate, disruption to business activities and, depending on their cause and severity, material damage to our reputation. We may also be liable for acts and omissions of sub-contractors or joint venture or consortium

19 partners which cause such loss or damage. Our insurance and our contractual limitations on liability may not adequately protect us against liability for such events, including events involving pollution, or against losses resulting from business interruption. In addition, indemnities which we receive from third parties may not be easily enforced if the relevant counterparties do not have adequate resources. Moreover, our insurance may not be able to address any such claims, we may not be able to ensure that every contract contains adequate limitations on liabilities and any claims made under our insurance policies are likely to cause our premiums to increase. Any future damage caused by our 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 may have a material adverse effect on our business, financial position and results of operations.

We conduct our business within a strict environmental regime and may be exposed to potential liabilities and additional regulatory measures that may result in project delays and higher costs We are subject to extensive and increasingly stringent laws and regulations relating to environmental protection in conducting the majority of our operations, including laws and regulations governing emissions into the air, discharge into waterways, and the generation, storage, handling, treatment and disposal of waste materials. We incur, and expect to continue to incur, increasing capital and operating costs to comply with environmental laws and regulations. The technical requirements of 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. We may also be subject to civil proceedings brought by environmental groups, local communities or other individuals, which could result in substantial claims, fines and penalties against us, as well as orders that could halt our operations.

Our business 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 applicable 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 us to obtain permits and comply with various other requirements. Governmental authorities may seek to impose fines or penalties on us, or revoke or deny issuance or renewal of operating permits for failure to comply with applicable laws and regulations. We have from time to time been subject to penalties relating to environmental accidents, and we 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 constructed or managed by us or otherwise resulting from our operations, and our insurance may not be able to address these claims. Any such fine, penalty or liabilities relating to environmental accidents may have a material adverse effect on our business, financial position and results of operations.

In respect of certain of the assets which we operate, we may be required by local law and/or contract to dismantle and dispose of assets that are no longer of use, in compliance with environmental or contractual standards. It is difficult to estimate and adequately provide for the costs involved in decommissioning an asset many years in the future, especially as environmental regulations and best practice are continually evolving. Decommissioning liabilities are subject to the accuracy of estimates of the future cost of the goods and services necessary to carry out the decommissioning and such estimates may be incorrect or underestimate the actual decommissioning costs upon commencement of decommissioning. We may not have provided adequately for such decommissioning costs, which may have a material adverse effect on our business, financial position and results of operations.

In addition, certain of our contracts subject us to possible claims if we fail 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, and we may be required to indemnify the resource owner for any losses arising out of an environmental incident or regulatory breach. 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 may require us to incur additional costs, halt or delay our operations, or become the basis of new or increased liabilities that may materially reduce earnings and cash available for operations, may harm our reputation and have a material adverse effect on our cash flows, business, financial position and results of operations.

We rely on the project performance of third parties, including sub-contractors, manufacturers and partners and may have legal liability for their actions We rely on third-party equipment manufacturers and sub-contractors in the execution and performance of our contracts and ordinary course activities. In the construction phase of our major EPC contracts, in particular, we

20 rely on a large number of sub-contractors. To the extent that we cannot engage sub-contractors or acquire equipment or materials according to our plans and budgets, our ability to complete a project or contract in a timely fashion or at a profit may be impaired. If the amount we are required to pay for these goods and services exceeds the amount estimated in bidding for fixed price work, we 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, we may be required to purchase such services, equipment or materials from another source at a higher price. Furthermore, where a sub-contractor fails to meet quality standards or to deliver its services or equipment according to negotiated terms or on time, we may be subject to claims. There can be no guarantee that we will be able to recover such costs from the relevant party. The resulting additional costs or claims may be substantial, and we may be required to compensate the project customer. We may not be able to recover these costs in whole or in part 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. Such events may have a material adverse effect on our reputation, cash flows, business, financial position and results of operations.

We are subject to counter-party credit risk of customers, joint venture and consortium partners and sub- contractors We provide our services to a variety of contractual counterparties and are therefore subject to the risk of non- payment for services we have rendered or non-reimbursement of costs we have incurred. The contracts which we enter into may require significant expenditure by us prior to receipt of relevant payments from the customer and expose us to potential credit risk. In addition, we are active in a number of markets where payment terms are not always met or where our 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, but such intervention may not always be successful in obtaining payment in whole or in part. We also enter into contracts with a joint venture or consortium representing the various asset owners and unless appropriate guarantees can be obtained by us, we are subject to a higher risk of non-payment when our contractual counterparty is a special purpose joint venture or consortium vehicle which does not have significant financial resources of its own, as such counterparties (particularly local partners in developing countries) may not be able to meet their financial or other obligations to the projects, potentially threatening the viability of such projects. Furthermore, should accidents or incidents occur in operations in which we participate, whether as operator or otherwise, and where it is held that our joint-venture and consortium partners or sub-contractors are legally liable to share any aspects of the cost of responding to such incidents, the financial capacity or protection provided by these third parties may prove inadequate to indemnify us fully against the costs we incur on behalf of the joint venture, consortium or contractual arrangements. There can be no guarantee that we will be able to recover such damages from the relevant third party. Failure by any of our contractual counterparties to pay for services provided, reimburse costs or indemnify claims incurred by us may have a material adverse effect on our cash flows, business, financial position and results of operations.

Our revenue, cash flows, earnings and backlog may vary in any period depending on a number of factors, including achievement of milestones on major contracts Revenue from our lump-sum contracts is recognised using the percentage-of-completion method of accounting, based on surveys of work performed once the outcome of a contract can be reliably estimated. This involves us recognising an increasing proportion of contract revenues and earnings as the contract progresses towards completion. For cost plus KPI based contracts, where costs are charged to customers with a fixed margin and we may also receive payment based on delivery of agreed KPIs, failure to achieve certain pre-agreed and monitored performance targets will also potentially reduce contract revenue and profits. Our revenues and earnings (or losses) are largely based on estimates of contract revenue, costs and profitability at completion and may not reflect actual revenues, earnings or losses to date on the contract. In addition, although revenue and earnings may be recognised for accounting purposes, these amounts do not represent actual cash received by us. Accordingly, there will be a difference, which can be significant, between our revenue and cash flows for any particular reporting period depending on the mix, structure and progress of the contracts we have entered into. When cash is received depends on the structure of each contract. Under certain of our OEC contracts for example, we may receive advance payments followed by payments on the achievement of set milestones, while under our OPO contracts we typically receive payment at regular intervals. Working capital may be volatile, reflecting the size and timing of cash advances on new OEC projects and the phasing of receipts and payments in respect of our existing portfolio of projects.

Cancellations of projects, delays in completion of contracts or delay or failure of customers to pay in a timely manner could affect the revenue, cash flows and earnings actually received from contracts and in certain

21 circumstances may result in a reduction, reversal or elimination of previously reported revenue or earnings. Furthermore, the inability to negotiate advance payments or favourable payment terms could have a material adverse effect on our cash flows. In addition, there can be no assurance that the future revenue projected in our backlog numbers will be ultimately realised, or will be realised in the timeframe expected or will result in profits, particularly in the event of project cancellation where we generally have no contractual right to the revenue reflected in our backlog. If we were to experience significant cancellations or delays of projects, such cancellations or delays may have a material adverse effect on our cash flows, business, financial position and results of operations.

Certain major projects and operations are conducted using consortium or joint venture partners and associates thereby reducing the degree of control we may exercise Increasingly, we may bid for a particular contract jointly with joint venture or consortium partners, and a number of our projects and operations are conducted through joint ventures or associates. For example, the recently- awarded contract for the Upper Zakum, UZ750 field development in Abu Dhabi will be undertaken in consortium with DSME. In addition, we have entered into a joint venture agreement with China Petroleum Engineering & Construction Corporation (“CPECC”) and a co-operation agreement with Schlumberger. These and other joint venture and consortium arrangements often involve complex risk allocation, decision-making processes and indemnification arrangements. In certain cases, we may have less control of such activities than we would have if we had full operational control. In these circumstances, our ability to maximise the profitability of any contract awarded to us may be adversely affected by the performance of our joint venture or consortium partners. In addition, we may be dependent on the expertise of partners in assessing certain costs of the contract. To the extent such costs are inaccurately calculated in relation to lump-sum contracts, we may be exposed to our share of any cost overruns of the joint venture or consortium, which may have a material adverse effect on our business, financial position and results of operations.

Furthermore, our joint venture or consortium partners may have economic or business interests or objectives that are inconsistent with, or opposed to, our interests or objectives and may exercise veto rights to block certain key decisions or actions that we believe are in our or the joint venture’s or associate’s best interests, or approve such matters without our consent. In addition, should accidents or incidents occur in operations in which we participate, whether as operator or otherwise, and where it is held that our joint-venture or consortium partners are legally liable to share any aspects of the cost of responding to such incidents, the financial capacity of these third parties may prove inadequate to indemnify us fully against the costs we incur on behalf of the joint venture or contractual arrangement.

We may be jointly and severally liable for the acts or omissions of our joint venture or consortium partners. This typically arises under the terms of the contract with our client, or may also arise under the terms of the joint venture or consortium arrangement or because we are exposed to the losses of any joint venture or consortium vehicle as we typically accept primary liability by way of a separate guarantee for the overall performance of the contract where we are only providing part of the goods or services to the customer. If a customer were to pursue claims against us or against a joint venture or consortium vehicle as a result of the acts or omissions of our partners, our ability to obtain recompense 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 may have a material adverse effect on our business, financial position and results of operations.

We may not accurately estimate the costs of, execute within budget, or may fail to complete, our contracts on time, or in the case of IES contracts may be forced to incur the costs of investment Under our lump-sum contracts (including major EPC contracts entered into by OEC and OCP), we perform our services and provide our products at a fixed price. If our cost estimate for a contract is inaccurate, or if we do not execute the contract within our cost estimates, cost overruns may cause the project to be less profitable than expected or cause us to incur losses which could be significant.

Our EPC projects generally involve complex design and engineering, significant procurement of equipment and supplies, and extensive construction management of large scale projects. Many projects are on-going for extended time periods, often in excess of three years, from initial award through to completion. During this time we may encounter difficulties in the design or engineering of the project or in equipment and service delivery, schedule changes or other disruption (such as political or local community unrest or prolonged adverse weather conditions), some of which may be beyond our control or which our insurance may not address, and any of which may impact our ability to complete the project within budget or in accordance with the original delivery

22 schedule. Delays in completion of a lump-sum project or failure to meet certain KPIs may cause us reputational damage, and may in certain circumstances also expose us to claims and liquidated damages payable to our clients, which increase our costs and all of which may have a material adverse effect on our cash flows, business, financial position and results of operations.

In addition, certain of our contracts, particularly those within IES, expose us to risks associated with the analysis, management and performance of reservoirs. If a reservoir fails to perform as anticipated, we may be required to continue to incur the costs of the investment or may not receive a return sufficient to recover our investment, which could result in reduced profitability or losses for us, and which may have a material adverse effect on our cash flows, business, financial performance and results of operations.

We are dependent on our senior personnel We depend on the continued services of our senior personnel, including our Directors and Senior Management, as their marketing, engineering, project management, financial and administrative skills are important to the successful operation of our business. We continue to review succession planning measures aimed at ensuring the development of our employees to provide successors, over time, for our existing Directors and Senior Management. However, there can be no assurance that these measures will be successful or that we will be able to attract, develop or retain executives of the right calibre. Our ability to meet our operational requirements and our future growth and profitability may be affected by the scarcity of senior management personnel. If we were to lose, or suffer an extended interruption of the services provided by a significant number of our Directors or Senior Management, or if we were unable to attract or develop a new generation of senior management, this may have a material adverse effect on our business, financial position and results of operations.

We operate in a competitive environment Contracts for our services are generally awarded following a competitive bidding process and while service quality, technological capacity, previous project performance, the quality of personnel, as well as reputation and experience, are considered in customer decisions, price is a major factor in most bid awards. In the past, the industry in which we operate has been frequently subject to price competition such that if price competition were to continue or intensify in the future, the number of bids that we believe will give us appropriate margins could decline and our financial performance could be adversely affected. In addition, many of our major competitors are diversified multinational companies that are large and have substantial financial resources making them better able to compete in providing faster, more efficient services or reduced prices, including by working for lower margins. These companies may also be more resilient to cyclical downturns in the oil and gas industry. Any of these competitive factors could cause us to lose market share in one or more of our key markets or strategic market position, which may have a material adverse effect on our business, financial position and results of operations.

Our businesses may be subject to litigation, including claims for negligence, and may not be covered or may be beyond our insurance coverage Our services involve the risk of contractual non-compliance and professional errors and omissions and other liability claims being made against us, as well as negative publicity that may adversely affect our financial position and results of operations. Furthermore, we provide performance warranties as to the services we provide and as to the proper operation and adherence to specifications of the plants and equipment we design, modify or construct. Failure of this equipment to operate properly or to meet specifications may give rise to claims against us and may increase our costs by requiring additional engineering resources and services, replacement of parts and equipment or monetary reimbursement to a customer and these failures may be significant and costly. We may not be able to maintain or obtain adequate insurance coverage to cover such litigation, warranty or other claims at rates we consider reasonable or we may take the decision not to insure such risks. Even where coverage is obtained, claims may be denied or exceed such insurance coverage and may harm our reputation and have a material adverse effect on our business, financial position and results of operations.

We are subject to trade controls, laws and regulations that could subject us to legal and regulatory risks As a result of our international activities, we are subject to the laws and regulations of, or pertaining to, the various countries in which we do business. Certain such countries are subject to economic sanctions, or restrictions and licensing requirements for exports of goods, software and technology, imposed by the United States, European Union, the United Kingdom and other jurisdictions in which we operate. These include, or have

23 in the past included, Iran, Sudan and Syria, where we believe our business did not and does not violate applicable economic sanctions or export controls laws and regulations. Due to such laws and regulations, business activities were terminated in Syria and Iran in 2011 and in Sudan by 30 August 2013. However, we cannot predict with confidence US, EU, UK or other applicable enforcement policies with respect to economic sanctions and export controls, and it is possible that the relevant authorities will take a different view regarding our status or the compliance measures we have taken in respect of prior or existing activity. Furthermore, laws, regulations or licensing policies on economic sanctions or export controls could change in a way that could affect our business, exports or sales in such countries or could result in restrictions, penalties or fines. In addition, changes to US, EU, UK or other applicable regulations could result in the restriction of our ability to continue with existing business and our ability to expand into new markets or to attract new customers. The imposition of economic sanctions on individuals or entities within the Group may result in persons or affiliates associated with us being subject to restrictions and penalties. Non-compliance with current or future applicable laws or regulations could result in civil or criminal liability for individuals and entities within the Group, joint venture or consortium partners or sub-contractors, the imposition of significant fines, the denial of export privileges, debarment from participation in government contracting, or other penalties, as well as negative publicity or reputational damage. In addition, we may generate revenue in other countries that become subject in the future to US, EU, UK or other applicable trade embargoes or sanctions which are currently not restricted, or could inadvertently conduct business with counterparties subject to such trade embargoes or sanctions. Any of the foregoing may have a material adverse effect on our business, financial position and results of operations.

We may encounter difficulties integrating future acquisitions or expanding into new business areas From time to time, we have made acquisitions pursuant to market opportunities, to increase our existing capabilities or expand into new areas of operation and we may make further acquisitions in the future. If such acquisitions are pursued and executed, we may encounter difficulties integrating these acquisitions into our business and in successfully realising the synergies or growth expected from such acquisitions. Furthermore, through an acquisition we may inherit liabilities from previous business activities. Failure to successfully integrate such acquisitions may have a material adverse effect on our business, financial position and results of operations.

Furthermore, our expansion into new business areas, whether geographical or through service lines such as IES and OCP, may expose us to additional business risks that are different from those that we have experienced to date. If we make a strategic decision to move into new regions or engage in new operations, we may fail to anticipate and provide for risks relating to such regions or operations. For example, when expanding into new regions we may be required to rely on subcontractors and vendors with whom we have little or no experience, or may have to comply with immature legal regimes which are difficult to understand and comply with. In addition, we may be unable to anticipate risks relating to commercial models, with which we have relatively little experience. Furthermore, we may not have developed the necessary skills to undertake new business activities, such as construction and installation in the deepwater offshore market. If we fail to anticipate or manage such risks successfully, we may not be able to recover our investments made during the course of such expansion, or could fail to put in place appropriate risk mitigation measures, and could incur losses and liabilities we had not anticipated, which may have a material adverse effect on our business, financial position and results of operations.

If a trend for owners of oil and gas installations to in-source the management of installations were to develop, we could lose customers Our business involves the provision of services to oil and gas companies who wish to outsource all or part of the management or operation of onshore and offshore assets. We do not believe that there is a trend for in-sourcing such assets or operations, but if such a trend were to develop, the number of existing or potential new customers may be reduced. If such a trend were to develop, for example in the UKCS, where our OPO service line acts as Duty Holder and we take on full responsibility for the safe management of offshore installations, it could cause us to lose existing customers. Furthermore, the IES division provides production enhancement solutions to a number of customers and if an in-sourcing trend were to develop, we could lose such customers. We may also lose employees (who could have been retained and redeployed elsewhere) if owners of facilities we manage were to choose to undertake management of such facilities and, accordingly, take the relevant employees, in-house. A reduction in demand for our services due to an increase in in-sourcing may have a material adverse effect on our business, financial position and results of operations.

Our long-term contracts may be subject to early termination, variation or non-renewal Certain of the contracts entered into by our subsidiaries are long-term contracts, which are performed over a period that often exceeds three years, and some of the contracts entered into by the IES division are for periods in

24 excess of 20 years. Any of our contracts may be terminated earlier than expected by our customers, either within the relevant notice periods or upon our default or non-performance. In such circumstances we may not receive compensation in respect of such early termination.

In addition, if certain of our contracts, particularly reimbursable PECs entered into by the IES division, were to be terminated early, we may not recover the capital invested by us in the project. Within our OPO service line, certain long-term contracts are subject to periodic renewal and there can be no guarantee that such contracts will be renewed and, if renewed, that the renewal will be on the same or improved commercial terms. The early termination or non-renewal of contracts would have an adverse impact on our business, financial position and results of operations as they may not be replaced by new contracts. Delays in the completion of a lump-sum project or failure to meet certain KPIs may, in certain circumstances, expose us to liquidated damages or other claims. Our contracts may also be subject to variation by renegotiation or by requiring us to provide a different level of service, which may result in reduced profitability or losses, which may have a material adverse effect on our cash flows, business, financial position and results of operations.

We rely on information technology systems for our operations We are dependent on our technology infrastructure and rely upon certain critical information systems for the effective operation of our business. We rely on our own internal information technology (“IT”) staff and third- party providers (such as Oracle for our Enterprise Resource Management System) to support the operations of the business. Sophisticated IT systems are vulnerable to a number of threats, such as software or hardware malfunctions, malicious hacking, physical damage to vital IT centres and computer virus infection. Any such malfunctions, hacking or physical damage could result in the loss of data, including proprietary know-how and trade secrets, and could disrupt our operations and materially and adversely affect our business. In addition, IT systems require regular upgrading to meet the needs of changing business and regulatory requirements and to keep pace with the requirements of our existing operations. In the future, we may not be able to implement necessary upgrades on a timely basis, and upgrades may fail to function as planned. Consequently, any major disruption of our existing IT systems may have a material adverse effect on our business, financial position and results of operations.

We are subject to fluctuations in foreign currency exchange rates Our reporting currency is the US dollar. In 2012, 34.5% of our revenue and 54.7% of our costs were denominated in currencies other than the US dollar. In the same period, the pound sterling, Kuwaiti dinar and euro accounted for 18%, 5% and 5% of our revenue, respectively, and 25%, 2% and 9% of our costs, respectively.

Two-thirds of the revenue and costs from our OPO service line are denominated in sterling. The US dollar contribution of the OPO service line in our reported results, and to our overall level of backlog, may therefore fluctuate with changes in sterling/US dollar exchange rate.

From time to time we enter into contracts or incur costs denominated in currencies other than US dollars or sterling and we may not always be able to match revenue with costs denominated in the same currency. Whilst we attempt to minimise our exposure to such foreign exchange risks through measures such as buying the local currencies of our 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 we will be able to successfully hedge and mitigate our foreign currency exchange risks in whole or in part. If we fail to successfully hedge or mitigate our foreign currency exchange risks, it may have a material adverse effect on our business, financial position and results of operations.

Limitations on our ability to protect our intellectual property rights, including trade secrets, could cause a loss in revenue and reduce any competitive advantage that we hold In providing our services we use both know-how which we regard as proprietary and certain intellectual property which we license from third parties. Where we have not protected our proprietary know-how by patents or other registered form of intellectual property right protection (or if our patents or other protections are inadequate) it is possible that third parties may access and utilise this know-how to our detriment. Our business may be adversely affected if it infringes patents or other intellectual property rights held by third parties or if certain licences are withdrawn or not renewed. In addition, we invest resources in building the goodwill and brand recognition applicable to the trademarked Petrofac names and the Petrofac “oil drop” logo. Failure to protect adequately our brand and goodwill may have a material adverse effect on our business, financial position and results of operations.

25 Our operations are susceptible to unforeseen catastrophic events and natural disasters Certain of our operations are located in areas at risk from the effects of natural disasters and other potentially catastrophic events, such as earthquakes, floods, hurricanes, riots, typhoons and wars. The occurrence of any of these events may disrupt our operations and materially and adversely affect our business, financial position and results of operations.

Severe weather conditions or climatic changes, resulting in conditions such as hurricanes, typhoons, dense fog, low visibility, heavy rains, wind and waves, may force us to temporarily suspend operations. For example, hurricanes have in the past forced us to delay operations or production. There can be no assurance that natural disasters will not occur and result in significant delays in project execution or major damage to important infrastructure facilities or cause significant disruption to operations, all of which may have a material adverse effect on our business, financial position and results of operations.

RISKS RELATING TO TAXATION Changes in certain fiscal regimes, tax incentives, agreements, treaties or concessions could adversely impact our financial position Changes in tax laws, exemptions and concessions Our profitability is impacted by the levels of direct and indirect taxation levied on our profits and services and on the profits and services of our customers in the locations in which we operate. Changes in tax laws or increases in the direct or indirect tax rates can adversely affect the returns that can be achieved by us and our customers and may result in a decline in profits. Some parts of the business rely on tax incentives and concessions, and withdrawal or expiry of such exemptions or concessions could have an adverse impact on the profit that can be achieved by us or our customers under the relevant contract and could, in certain cases, lead us or our customers to question the economic viability of their presence in that country. In addition, the interpretation of guidelines, rules and legislation by governmental tax authorities in the countries in which we operate may change from time to time. Our conduct of operations may not be held to be consistent with such changes in interpretation, which could require us to change aspects of our operations which may correspondingly lead to a decline in revenue and profits. Moreover, changes in tax rules or guidance or in their interpretation may have retrospective effect. Any of the above may have a material adverse effect on our business, financial position and results of operations.

In connection with changes in tax laws, the UK Government has recently held a consultation on “strengthening obligations to ensure that the correct Income Tax and National Insurance Contributions (“NIC”) are paid by offshore employment intermediaries”, including those in the oil and gas sector. Draft legislation to amend the NIC rules with effect from 6 April 2014 is currently before the UK Parliament, and draft income tax legislation has been published for consultation with a view to enactment in the Finance Act 2014, though in each case, specific guidance in relation to the oil and gas sector has not yet been published. We do not expect that any revised rules will adversely affect the Group to a disproportionate extent compared with its competitors. However, if this is not the case, or if the UK tax authorities were to successfully challenge the current arrangements, it may have a material adverse effect on our business, financial position and results of operations.

Changes in or challenges to the application or interpretation of international treaties Our international allocation of revenue and profits, and hence our global tax profile, depend on numerous international tax treaties.

On 19 July 2013, the Organisation for Economic Cooperation and Development published its Action Plan on Base Erosion and Profit Shifting (the “BEPS Action Plan”), which proposes fifteen actions intended to counter international tax base erosion and profit shifting, including the amendment of tax rules on controlled foreign companies, permanent establishments and transfer pricing.

A change in the application or interpretation of any relevant tax treaties, a challenge by the authorities to such application or interpretation, or a change in the international allocation of revenue and profits and hence our global tax profile (in each case, whether pursuant to the BEPS Action Plan or otherwise), could have material adverse tax implications for us or may otherwise have a material adverse effect on our business, financial position and results of operations.

Changes in agreements with tax authorities In a number of jurisdictions in which we operate, the tax treatment of one or more of our entities is governed by agreements with local tax authorities, rather than solely by tax laws and tax authorities’ published practice.

26 Changes to or the termination of such agreements, or the interpretation or application of those agreements in an unexpected manner by local tax authorities or courts, could have adverse tax implications for us, potentially including penalties, interest and charges in relation to current or previous years, which may have a material adverse effect on our business, financial position and results of operations.

If the Company or certain of its affiliates were deemed to be resident for taxation purposes outside the jurisdictions in which they are currently tax resident, this could have adverse tax implications Although our Group as a whole pays tax in the jurisdictions in which we operate in accordance with local regulations, certain members of our Group are only resident for tax purposes in certain jurisdictions. For example, the Company itself, which is the Group holding company, and certain of its subsidiaries are tax resident in Jersey. While we have no reason to believe that any authority in any other jurisdiction could successfully claim that any member of our Group 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 relevant member of our Group could face penalties, interest and charges to taxation in respect of current and earlier years, which may have a material adverse effect on our business, financial position and results of operations.

Weaknesses in the tax system and legislation, and lack of specific tax legislation governing some of our contractual arrangements in some of the countries in which we operate, could create an uncertain environment for our business activity and could subject us to additional material tax liabilities We operate in various jurisdictions and tax legislation that is currently in effect in some of these jurisdictions is not sophisticated or well developed and is subject to varied interpretations by the local authorities. Moreover, our business in such jurisdictions and the contractual arrangements under which we operate may not be specifically or clearly addressed in such tax systems. Despite our reasonable efforts to comply with the applicable tax legislation, relevant concessions, and the terms of any negotiated or formalised agreement with the relevant tax authorities, the application of the relevant laws to all or any individual part of a contractual arrangement is at the discretion of local authorities. The selective or arbitrary application of such tax legislation, concession or negotiated agreement, or the departure from the terms of such an agreement, could complicate our tax planning and business decisions. Furthermore, such collective or arbitrary application puts our existing arrangements and structures at risk of sudden and unexpected tax audits, which may have a material adverse effect on our business, financial position and results of operations.

From time to time, we are, and have been, assessed to tax in an arbitrary manner. Such assessments are appealed and defended on an appropriate and reasonable basis, and adequate provisioning is made in consultation with our professional advisers and reviewed by our external auditors. However, such provisions may prove to be insufficient to cover any eventual liability. Additionally, although provisions are held until we have appropriate assurance that the relevant liability will not crystallise, a liability may crystallise even if the associated provision has been discharged.

RISKS RELATING TO THE NOTES Because the Company is a holding company, it is financially dependent on receiving advances or distributions from our subsidiaries The Company is a holding company and all of its operations are conducted through its subsidiaries. Consequently, it relies on dividends or advances from its subsidiaries, including those that are not wholly-owned, to fund its operations. The ability of these subsidiaries to pay dividends or advances, and the Company’s ability to receive distributions from its investments in other entities such as joint venture vehicles, is subject to applicable local laws and other restrictions, including, but not limited to, the entities having sufficient retained earnings, limitation on the repatriation of funds and applicable tax laws. Furthermore, distributions from joint ventures are often contingent on the agreement of our joint venture partners, who may not give such permission. These laws and restrictions, contractual or otherwise, could limit the payment of dividends and distributions, which may restrict the Company’s ability to fund its operations including payments due under the Notes.

An active liquid trading market for the Notes may not develop, and the transfer of the Notes will be subject to restrictions We have applied for the listing of the Notes on the Global Exchange Market. However, we cannot assure you that the Notes will be listed on any exchange at the time the Notes are delivered to the Initial Purchasers or at any

27 other time. The Initial Purchasers have informed us that they intend to make a market in the Notes. However, they are not obligated to do so, and may discontinue such market making at any time without notice. There can be no assurance that an active trading market for the Notes will develop, or if one does develop, that it will be sustained.

We have not registered the Notes under the Securities Act or any US state securities laws, and we have not agreed to and do not intend to register the Notes under the Securities Act or under any other country’s securities laws. Therefore, you may not offer or sell the Notes, except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. You should read the discussion under the heading “Notice to Investors” for further information about the transfer restrictions that apply to the Notes. It is your obligation to ensure that your offers and sales of Notes within the United States and other countries comply with all applicable securities laws.

We may be able to incur substantially more debt in the future We may be able to incur substantial additional indebtedness in the future, including in connection with future acquisitions, some of which may be secured by some or all of our assets. The terms of the Notes will not limit the amount of indebtedness we may incur. Any such incurrence of additional indebtedness could exacerbate the related risks that we now face.

Credit ratings may not reflect all risks Both S&P and Moody’s are expected to assign credit ratings to the Notes. The ratings may not reflect the potential impact of all risks related to structure, market, additional factors discussed above, and other factors that may affect the value of the Notes. A credit rating is not a recommendation to buy, sell or hold securities and may be revised or withdrawn by the rating agency at any time.

The Notes are structurally subordinated to all of the debt and liabilities of our subsidiaries except the Guarantors Holders of Notes will have a direct claim based on the Notes against the Issuer and, based on the Guarantees, against the Guarantors, but will not have a direct claim based on the Notes or the Guarantees against any of our other subsidiaries, including operating or asset-holding subsidiaries. The right of the holders of Notes to receive payments under the Notes and the Guarantees will be structurally subordinated to all liabilities of our subsidiaries except the Guarantors (so long as their respective Guarantees are in effect), including our operating and asset- holding subsidiaries and associated companies. In the event of a bankruptcy, liquidation, reorganisation or similar proceeding relating to a subsidiary, the right of holders of Notes to participate in a distribution of the assets of such subsidiary will rank behind such subsidiary’s and associated companies’ creditors (including trade creditors) and preferred stockholders (if any), except to the extent that the Issuer or any of the Guarantors has direct claims against such subsidiary. See “Business—Description of the Business”, “Operating and Financial Review—Liquidity and Capital Resources—Indebtedness” and “Description of Notes and Guarantees—Status of Notes and Guarantees”.

The financial information contained in this Offering Memorandum may be of limited use in assessing the financial position of the Guarantors In 2012, our non-guarantor subsidiaries represented 21% of our EBITDA and 36% of our net assets. See “The Guarantors—Selected Company and Guarantor Information”. We are not including separate financial information in respect of our guarantor or non-guarantor subsidiaries in this Offering Memorandum and the consolidated financial information may be of limited use in assessing the financial position of the Guarantors.

The Notes will initially be held in book-entry form and therefore you must rely on the procedures of relevant clearing systems to exercise any rights and remedies Unless and until Notes in definitive registered form, or definitive registered Notes, are issued in exchange for book-entry interests, owners of book-entry interests will not be considered owners or holders of Notes. DTC, or its nominee, will be the registered holder of the Global Notes for the benefit of its participants, including Euroclear and Clearstream. After payment to the registered holder, we will have no responsibility or liability for the payment of interest, principal or other amounts to the owners of book-entry interests. Accordingly, if you own a book-entry interest, you must rely on the procedures of DTC, Euroclear or Clearstream and if you are not a

28 participant in DTC, Euroclear or Clearstream, on the procedures of the participants through which you own your interest, to exercise any rights and obligations of a holder under the Fiscal and Paying Agency Agreement. See “Book-Entry, Delivery and Form”.

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

Similarly, upon the occurrence of an event of default under the Fiscal and Paying Agency Agreement, unless and until definitive registered Notes are issued in respect of all book-entry interests, if you own a book-entry interest, you will be restricted to acting through DTC, Euroclear or Clearstream. The procedures to be implemented through DTC, Euroclear or Clearstream may not be adequate to ensure the timely exercise of rights under the Notes. See “Book-Entry, Delivery and Form”.

The Notes are subject to optional redemption, which may limit their market value The optional redemption feature of the Notes is likely to limit their market value. During any period when we may elect to redeem the Notes, the market value of those Notes generally will not rise substantially above the price at which they can be redeemed. This also may be true prior to any redemption period. We may be expected to redeem Notes when our cost of borrowing is lower than the interest rate on the Notes. At those times, an investor generally might not be able to reinvest the redemption proceeds at an effective interest rate as high as the interest rate on the Notes being redeemed and may only be able to do so at a significantly lower rate. Potential investors should consider reinvestment risk in light of other investments available at that time.

We may be unable to repurchase the Notes upon a change of control Upon the occurrence of a change of Change of Control Repurchase Event, as described in “Description of Notes and Guarantees—Change of Control Repurchase Event”, we will be required to offer to repurchase all outstanding Notes at 101% of their principal amount plus accrued and unpaid interest. Our source of funds for any such purchase of the Notes will be available cash, cash generated from our subsidiaries or other sources, including borrowings, sales of assets or sales of equity. The sources of cash may not be adequate to permit us to repurchase the Notes upon a change of control. Any failure on our part to offer to repurchase the Notes, or to repurchase Notes tendered following a change of control, may result in a default under the Fiscal and Paying Agency Agreement, which could lead to a cross-default under the terms of our existing and future indebtedness. For further information, see “Description of Notes and Guarantees—Change of Control Repurchase Event”.

Your rights as a holder of the Notes may be altered without your consent The terms of the Notes contain provisions for calling meetings of holders to consider matters affecting their interests generally. These provisions permit defined majorities to bind all holders of the Notes, including holders who did not attend and vote at the relevant meeting and holders who voted in a manner contrary to the majority. The terms of the Notes also provide that we may, without the consent of holders of the Notes, agree to any modification (not being a modification requiring the approval of a meeting of holders of the Notes) of any provision of the Notes which is not materially prejudicial to the interests of the holders of the Notes or any modification of the Notes which is of a formal, minor or technical nature or is made to correct a manifest error, in the circumstances described in “Description of Notes and Guarantees—Modification and Waiver”.

The Notes are unsecured obligations of the Issuer and are subordinated to secured obligations on insolvency Holders of any secured obligations of the Issuer or Guarantors will have claims that are prior to the claims of holders of the Notes to the extent of the value of the assets securing those other obligations. The Notes are effectively subordinated to secured indebtedness to the extent of the value of the assets securing those other obligations. In the event of any distribution of assets or payment in any dissolution, winding-up, liquidation, reorganisation, or other bankruptcy proceeding, the assets securing the claims of secured creditors will be available to satisfy the claims of those creditors, if any, before they are available to unsecured creditors, including the holders of the Notes. In any of the foregoing events, there is no assurance to holders of the Notes that there will be sufficient assets to pay amounts due on the Notes.

29 Corporate benefit laws and other limitations on the Guarantees may adversely affect the validity and enforceability of the Guarantees The Guarantees provide the holders of the Notes with a direct claim against the assets of the Guarantors. The Guarantees, however, will be limited to the maximum amount that would not render the Guarantors’ obligations subject to avoidance under applicable fraudulent conveyance, corporate benefit or other applicable laws. In addition, enforcement of the Guarantees or security against the Guarantors will be subject to certain defences available to the Guarantors. These laws and defences include those that relate to fraudulent conveyance or transfer, proof of the existence and the quantum of the underlying obligation, proof of default of the underlying obligation, defences otherwise available to the Issuer, voidable preference, corporate purpose or benefit and regulations or defences affecting the rights of creditors generally. Petrofac International (UAE) LLC would also be able to assert that the quantum of its Guarantees is capped by the quantum of the underlying obligation, and would be able to assert the six-month time bar on actions on guarantees that is contained in the UAE Civil Code. If one or more of these laws and defences are applicable, one or both of the Guarantors may have no liability or decreased liability under the Guarantees.

Exchange rate risks and exchange controls may adversely impact currency conversions of principal and interest paid on the Notes We will pay principal and interest on the Notes in US dollars. This presents certain risks relating to currency conversions if an investor’s financial activities are denominated principally in a currency or currency unit (the “Investor’s Currency”) other than US dollars. These include the risk that exchange rates may significantly change (including changes due to devaluation of the US dollar or revaluation of the Investor’s Currency) and the risk that authorities with jurisdiction over the Investor’s Currency may impose or modify exchange controls. An appreciation in the value of the Investor’s Currency relative to the US dollar would decrease the Investor’s Currency-equivalent yield on the Notes, the Investor’s Currency-equivalent value of the principal payable on the Notes and the Investor’s Currency-equivalent market value of the Notes. Governments and monetary authorities may impose (as some have done in the past) exchange controls that could adversely affect an applicable exchange rate. As a result, investors may receive less interest or principal than expected, or no interest or principal.

30 USE OF PROCEEDS

It is anticipated that the net proceeds of the Offering will be approximately US$745 million. We intend to use the majority of the net proceeds from the Offering to reduce the amount outstanding under the Revolving Credit Facility and the rest for general corporate purposes. For more information, see “Capitalisation”.

31 CAPITALISATION

The table below presents our consolidated capitalisation and certain other balance sheet information as of 30 June 2013 on an actual basis and as adjusted to reflect the issuance and sale of the Notes and the application of the net proceeds from such sale. You should read this table together with the sections of this Offering Memorandum entitled “Use of Proceeds”, “Selected Financial Statements and other Data” and “Operating and Financial Review” and with our Financial Statements and related notes included elsewhere in this Offering Memorandum.

The capitalisation information presented as adjusted has been prepared for the purpose of showing the effect of the issue of the Notes on the applicable items in the table below as if it had occurred on 30 June 2013, and has been prepared for illustrative purposes only. By its nature such information addresses a hypothetical situation and therefore does not reflect our actual financial position. The capitalisation information presented as adjusted is compiled in a manner consistent with our accounting policies in preparing our Financial Statements.

As of 30 June 2013 Actual As Adjusted(1) (unaudited) (US$ millions) Cash and short-term deposits(2) ...... 538 563 Debt Bank overdrafts(3) ...... 53 53 Notes offered hereby ...... — 750(4) Project financing(5) ...... 148 148 Revolving Credit Facility(6) ...... 720 — Total debt ...... 921 951 Total shareholders’ equity(7) ...... 1,600 1,600 Total capitalisation(8) ...... 2,521 2,551

(1) The figures contained in the adjusted column reflect the issuance and sale of the Notes offered hereby and the application of the net proceeds from such sale. We intend to use the majority of the net proceeds from the Offering to reduce the amount outstanding under the Revolving Credit Facility and the rest for general corporate purposes. See “Use of Proceeds”. (2) Our cash and short-term deposits as of 31 August 2013 were US$511 million. On 11 September 2013, Petrofac Emirates, our Abu Dhabi based joint venture, received an advance payment of approximately US$290 million in respect of the Upper Zakum UZ750 field development project in Abu Dhabi. (3) Bank overdrafts were US$26 million as of 31 August 2013. (4) Net proceeds from the Notes of US$745 million plus expenses and issue discounts. (5) Project Financing represents our share of the senior secured term loan facility entered into by our joint venture project, BFPL. Our wholly owned subsidiary PED owns a 51% share of BFPL. See “Operating and Financial Review—Liquidity and Capital Resources—Indebtedness—Project Financing”. (6) The Revolving Credit Facility balance excludes the unamortised debt acquisition costs of US$11 million. As of 31 August 2013, we had a balance under our Revolving Credit Facility of US$939 million. On 23 September 2013 we made a payment of US$157 million to the Revolving Credit Facility, bringing the outstanding balance to US$782 million as of 26 September 2013. For purposes of this table, we have assumed that we will reduce the amount of the Revolving Credit Facility outstanding by US$720 million. See “Use of Proceeds”. (7) Total shareholders’ equity does not include non-controlling interests. (8) Total capitalisation represents the sum of total debt and total shareholders’ equity.

32 SELECTED FINANCIAL STATEMENTS AND OTHER DATA

The information presented herein is extracted without material adjustment from the Company’s Financial Statements, which have been prepared in accordance with IFRS. You should read the information below in conjunction with the Company’s unaudited 2013 Interim Condensed Consolidated Financial Statements and its audited Consolidated Financial Statements and the corresponding auditors’ reports for these periods, the detailed information included in this Offering Memorandum, and you should not rely solely on key and summarised information. The Financial Statements begin on page F-1 of this Offering Memorandum. Ernst & Young LLP of 1 More London Place, London SE1 2AF, has issued an unqualified review report and unqualified audit opinions in respect of the Company’s 2013 Interim Condensed Consolidated Financial Statements and Consolidated Financial Statements, respectively.

Consolidated Income Statement

Six Months Ended Year Ended 30 June 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Revenue ...... 2,794 3,187 6,324 5,801 4,354 Cost of sales ...... (2,292) (2,655) (5,244) (4,841) (3,595) Gross profit ...... 502 532 1,080 960 759 Selling, general and administration expenses ...... (217) (176) (359) (283) (222) Gain on EnQuest demerger ...... — ———125 Other income ...... 8 46 65 12 5 Other expenses ...... (8) (9) (20) (5) (4) Profit from operations before tax and finance (costs)/income .. 285 393 766 684 663 Finance costs ...... (6) (2) (5) (7) (5) Finance income ...... 11 3 12 8 10 Share of profits/(losses) of associates/joint ventures ...... 10 19 (8) (4) — Profit before tax ...... 300 413 765 681 668 Income tax expense ...... (58) (89) (135) (141) (110) Profit for the year ...... 242 324 630 540 558 Profit for the year attributable to: Petrofac Limited shareholders ...... 243 326 632 540 558 Non-controlling interests ...... (1) (2) (2) — — 242 324 630 540 558 Earnings per share (US cents) Basic ...... 71.24 95.55 185.55 159.01 127.76(2) Diluted ...... 70.72 94.82 183.88 157.13 126.09(2) (1) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement on such line items. (2) This amount excludes the gain on the EnQuest demerger.

33 Consolidated Statement of Financial Position

As of 30 June As of December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Assets Non-current assets Property, plant and equipment ...... 907 664 905 594 287 Goodwill ...... 147 120 125 107 106 Intangible assets ...... 358 178 307 122 86 Investments in associates/joint ventures ...... 199 226 177 164 16 Available-for-sale financial assets ...... ————102 Other financial assets ...... 530 334 444 140 2 Deferred income tax assets ...... 48 33 43 29 26 2,189 1,555 2,001 1,156 625 Current assets Non-current asset held for sale ...... — — — 44 — Inventories ...... 38 22 27 11 7 Work in progress ...... 742 964 656 612 804 Trade and other receivables ...... 1,975 1,297 1,915 1,353 1,057 Due from related parties ...... 29 10 22 99 — Other financial assets ...... 171 20 85 30 42 Income tax receivable ...... 6 9 12 15 3 Cash and short-term deposits ...... 538 790 614 1,572 1,063 3,499 3,112 3,331 3,736 2,976 Total assets ...... 5,688 4,667 5,332 4,892 3,601 Equity and liabilities Equity attributable to Petrofac Limited shareholders Share capital ...... 77777 Share premium ...... 44421 Capital redemption reserve ...... 11 11 11 11 11 Shares to be issued ...... ———— 1 Treasury shares ...... (114) (105) (100) (75) (65) Other reserves ...... 9 (3) 38 6 34 Retained earnings ...... 1,683 1,355 1,589 1,161 787 1600 1,269 1,549 1,112 776 Non-controlling interests ...... 51133 Total equity ...... 1,605 1,270 1,550 1,115 779 Non-current liabilities Interest-bearing loans and borrowings ...... 835 2 292 16 40 Provisions ...... 106 70 100 60 46 Other financial liabilities ...... 6 13 8 24 11 Deferred income tax liabilities ...... 102 97 143 60 48 1,049 182 543 160 145 Current liabilities Trade and other payables ...... 1,927 1,669 1,981 1,742 1,021 Due to related parties ...... 1 58 38 23 12 Interest-bearing loans and borrowings ...... 73 65 57 61 47 Other financial liabilities ...... 19 22 17 32 37 Liabilities directly associated with non-current asset held for sale ...... — — — 5 — Income tax payable ...... 138 99 75 96 106 Billings in excess of cost and estimated earnings ...... 365 274 328 389 178 Accrued contract expenses ...... 511 1,028 743 1,269 1,276 3,034 3,215 3,239 3,617 2,677 Total liabilities ...... 4,083 3,397 3,782 3,777 2,822 Total equity and liabilities ...... 5,688 4,667 5,332 4,892 3,601

34 Consolidated Statement of Cash Flows

Investing activities Purchase of property, plant and equipment ...... (201) (149) (397) (420) (115) Acquisition of subsidiaries, net of cash acquired ...... 62 (15) (20) — (15) Payment of contingent consideration on acquisition ...... — — (1) (16) — Purchase of other intangible assets ...... (16) — (7) (6) — Purchase of intangible oil and gas assets ...... (44) (54) (165) (40) (16) Cash outflow on EnQuest demerger (including transaction costs) ...... — — — — (18) Investments in associates ...... — — (25) (50) (8) Dividend received from a joint venture ...... 2 — — — — Purchase of available-for-sale financial assets ...... — — (101) Proceeds from disposal of property, plant and equipment ...... — — 1 — 3 Proceeds from disposal of non-current asset held for sale ...... — 60 60 — — Proceeds from sale of intangible assets ...... — — — — 6 Proceeds from disposal of an investment in a joint venture ...... — — 5 — — Interest received ...... 1 3 5 9 10 Net cash flows used in investing activities ...... (196) (155) (544) (523) (254)

35 Six Months Ended Year Ended 30 June 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Financing activities Interest bearing loans and borrowings obtained, net of debt acquisition cost ...... 568 — 291 — — Repayment of interest-bearing loans and borrowings ...... (9) (11) (50) (19) (32) Treasury shares purchased ...... (45) (76) (76) (49) (37) Equity dividends paid ...... (148) (128) (201) (159) (132) Net cash flows used in financing activities ...... 366 (215) (36) (227) (201)

Net (decrease)/ increase in cash and cash equivalents ...... (39) (771) (981) 513 (349) Net foreign exchange difference ...... 1 (11) 3 (12) (8) Cash and cash equivalents at 1 January ...... 525 1,535 1,535 1,034 1,391 Cash and cash equivalents at period end ...... 485 753 557 1,535 1,034

Segmental Information The following table shows the breakdown of revenue, profit attributable to Petrofac Limited shareholders and profit margin by reporting segment for the periods indicated:

Profit Attributable to Petrofac Revenue Shareholders(1) Profit Margin(2) Six Months Year Ended Six Months Year Ended Six Months Year Ended Ended 30 June 31 December Ended 30 June 31 December Ended 30 June 31 December 2013 2012(3) 2012 2011 2010(4) 2013 2012(3) 2012 2011 2010(4) 2013 2012(3) 2012 2011 2010(4) (unaudited) (audited) (unaudited) (audited) (unaudited) (audited) (US$ millions) (percent) Onshore Engineering & Construction . . . 1,610 2,333 4,358 4,146 3,254 171 251 479 463 373 10.6 10.8 11.0 11.2 11.5 Offshore Projects & Operations ..... 670 661 1,403 1,252 722 12 31 61 44 17 1.8 4.7 4.3 3.5 2.4 Engineering & Consulting Services ...... 180 103 248 208 173 6 5 29 31 21 3.3 5.8 11.7 14.8 12.2 Integrated Energy Services ...... 419 318 719 519 384 43 64 89 22 38 10.3 20.1 12.4 4.4 9.9 Corporate, consolidation & elimination .... (85) (228) (404) (324) (179) 11 (25) (26) (20) (16) Group ...... 2,794 3,187 6,324 5,801 4,354 243 326 632 540 433 8.7 10.2 10.0 9.3 9.9

(1) For 2010, profit attributable to Petrofac Limited shareholders excludes US$125 million from the gain on the EnQuest demerger. (2) Profit margin is profit attributable to Petrofac Limited shareholders represented as a percentage of revenue. (3) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement on such line items. (4) The segmental comparative 2010 figures were restated in our 2011 Consolidated Financial Statements to reflect our revised organisational structure. See “Operating and Financial Review—Basis of Preparation of Financial Information”.

36 Other Non-IFRS Financial Information EBITDA and Operating Profit The following table shows EBITDA and operating profit by reporting segment for the periods indicated:

EBITDA(1) Operating Profit(1) Six Months Ended Year Ended Six Months Ended Year Ended 30 June 31 December 30 June 31 December 2013 2012(2) 2012 2011 2010 2013 2012(2) 2012 2011 2010 (unaudited) (unaudited) (unaudited) (unaudited) (US$ millions) Onshore Engineering & Construction ...... 224 318 580 585 472 190 299 540 554 438 Offshore Projects & Operations ..... 29 44 95 62 27 20 42 79 57 24 Engineering & Consulting Services ...... 9 7 36 40 26 6 4 30 33 20 Integrated Energy Services ...... 116 110 196 89 128 57 90 133 53 74 Corporate, consolidation & elimination ...... 27 (24) (19) (16) (19) 22 (23) (24) (17) (17) Group ...... 405 455 888 760 634 295 412 758 680 539

Six Months Ended 30 June 2013 Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 197 19 6 64 (5) 19 300 Finance income ...... (7) — — (10) (10) 16 (11) Finance costs ...... — 1 — 3 10 (8) 6 Operating profit ...... 190 20 6 57 (5) 27 295 Depreciation, amortisation and write-offs ...... 34 9 3 59 6 (1) 110 EBITDA ...... 224 29 9 116 1 26 405

Six Months Ended 30 June 2012(2) Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 303 42 4 88 (3) (21) 413 Finance income ...... (4) — — — (3) 4 (3) Finance costs ...... — — — 2 2 (2) 2 Operating profit ...... 299 42 4 90 (4) (19) 412 Depreciation, amortisation and write-offs ...... 19 2 3 20 — (1) 43 EBITDA ...... 318 44 7 110 (4) (20) 455

37 Year Ended 31 December 2012 Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 548 79 31 136 5 (34) 765 Finance income ...... (8) — (1) (7) (9) 13 (12) Finance costs ...... — — — 4 6 (5) 5 Gain on the EnQuest demerger ...... — — — — — — — Operating profit ...... 540 79 30 133 2 (26) 758 Amortisation and impairment ...... — 1 1 8 1 — 11 Depreciation ...... 40 15 5 55 6 (2) 119 EBITDA ...... 580 95 36 196 9 (28) 888

Year Ended 31 December 2011 Onshore Engineering Consolidation Engineering Offshore & Integrated Adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & Other Eliminations Total (unaudited) (US$ millions) Profit before tax ...... 561 56 33 50 (10) (9) 681 Finance income ...... (9) — — — (2) 3 (8) Finance costs ...... 2 1 — 3 3 (2) 7 Gain on the EnQuest demerger ...... — — — — — — — Operating profit ...... 554 57 33 53 (9) (8) 680 Amortisation and impairment ...... — 1 1 1 — — 3 Depreciation ...... 31 4 6 35 1 — 77 EBITDA ...... 585 62 40 89 (8) (8) 760

38 Net Cash / (Debt) The following table shows net cash / (debt) for the periods indicated:

(1) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement on such line items. (2) The Revolving Credit Facility and interest bearing loans and borrowings balances exclude unamortised debt acquisition costs and effective interest rate adjustments. (3) Project Financing represents our share of the senior secured term loan facility entered into by our joint venture project, BFPL. Our wholly owned subsidiary PED owns a 51% share of BFPL. See “Operating and Financial Review—Liquidity and Capital Resources—Indebtedness—Project Financing”.

39 OPERATING AND FINANCIAL REVIEW

This Operating and Financial Review contains forward-looking statements that involve risks and uncertainties. See the section of this Offering Memorandum headed “Forward-looking Statements” for a discussion of the uncertainties, risks and assumptions associated with these statements. The following discussion should be read in conjunction with the historical consolidated financial information and the notes related thereto and the other financial information relating to us beginning on page F-1 of this Offering Memorandum. The results of operations for the periods reflected herein are not necessarily indicative of results that may be expected for future periods, and our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors including, but not limited to, those listed under the section of this Offering Memorandum headed “Risk Factors” and included elsewhere in this Offering Memorandum. Please refer to the section of this Offering Memorandum headed “Presentation of Financial and other Information” for more information on the financial information and statements that form the basis of this discussion.

Overview Since our inception in 1981 as a Texas-based designer and fabricator of modular plant, we have grown to become a FTSE 100 company with operations in 29 countries. In over three decades of operations, we have developed a wide range of skills and capabilities, which we use to help hydrocarbon resource holders develop and unlock the value of new and existing oil and gas assets, both onshore and offshore. As of 30 August 2013, Petrofac Limited had a market capitalisation of US$7.4 billion. We have a broad global footprint across a number of high-growth countries and regions, and our operations are run out of seven main operating centres in Aberdeen, Sharjah, Woking, Chennai, Mumbai, Abu Dhabi and Kuala Lumpur. We had 18,565 employees in 24 offices and 14 training centres across 29 countries worldwide as of 30 June 2013. For the six months ended 30 June 2013, the United Kingdom accounted for 27% of our revenue, while Algeria, Turkmenistan, Malaysia, UAE, Iraq, Kuwait and Mexico accounted for 13%, 12%, 10%, 7%, 7%, 5% and 4% of our revenue, respectively. For the year ended 31 December 2012, Turkmenistan accounted for 27% of our revenue and the United Kingdom accounted for 19% of our revenue, while Algeria, the UAE, Malaysia, Kuwait and Qatar accounted for 14%, 13%, 7%, 5%, and 4% of our revenue, respectively.

The following table sets forth our revenue, EBITDA, operating profit and profit attributable to Petrofac Limited shareholders for the periods indicated:

Six Months Ended 30 June Year Ended 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) (US$ millions) Revenue ...... 2,794 3,187 6,324 5,801 4,354 EBITDA(2) (3) ...... 405 455 888 760 634 Operating profit(2) (4) ...... 295 412 758 680 539 Profit attributable to Petrofac Limited shareholders(5) ...... 243 326 632 540 433 (1) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement on such line items. (2) Unaudited. (3) EBITDA represents profit before tax adjusted for finance income, finance costs, depreciation, amortisation and impairment, as well as exceptional items such as the gain on the EnQuest demerger in 2010. (4) Operating profit represents profit before tax adjusted for finance income and finance costs as well as exceptional items such as the gain on the EnQuest demerger in 2010. (5) For 2010, profit attributable to Petrofac Limited shareholders excludes the gain on the EnQuest demerger of US$125 million.

The scale and depth of our business allows us to provide services to our customers across the life cycle of oil and gas assets. Our capabilities run from conceptual and detailed design to building onshore and offshore greenfield and brownfield projects, operating and maintaining oil and gas infrastructure, managing oil and gas assets, training personnel and integrating our spectrum of technical skills to support customers in developing their hydrocarbon resources. We are organised into two divisions: ECOM and IES, which together operate through seven service lines that report under four reporting segments.

40 Through the ECOM division, which is split into three reporting segments, we design and build oil and gas facilities and operate, manage and maintain them on behalf of our customers. The IES division, which is a single reporting segment, leverages our capabilities to provide integrated services to oil and gas resource holders.

For the six months ended 30 June 2013, the ECOM division accounted for 85% of our revenue, 69% of our EBITDA, 79% of our operating profit and 81% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, the ECOM division accounted for 89% of our revenue, 78% of our EBITDA, 83% of our operating profit and 86% of our profit attributable to Petrofac Limited shareholders. ECOM operations are split into three distinct reporting segments which are focused predominately on markets in the Middle East, the UKCS, Africa and the CIS: • OEC delivers onshore EPC projects. For the six months ended 30 June 2013, OEC accounted for 56% of our revenue, 59% of our EBITDA, 70% of our operating profit and 74% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, OEC accounted for 64% of our revenue, 64% of our EBITDA, 69% of our operating profit and 73% of our profit attributable to Petrofac Limited shareholders. • OPO specialises in onshore and offshore operations and maintenance and brownfield modification projects and, through the OCP service line, specialises in providing offshore EPIC services for greenfield projects. For the six months ended 30 June 2013, OPO accounted for 23% of our revenue, 8% of our EBITDA, 7% of our operating profit and 5% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, OPO accounted for 21% of our revenue, 10% of our EBITDA, 10% of our operating profit and 9% of our profit attributable to Petrofac Limited shareholders. • ECS delivers early-stage engineering studies, including conceptual and FEED work across onshore and offshore oil and gas fields. For the six months ended 30 June 2013, ECS accounted for 6% of our revenue, 2% of our EBITDA, 2% of our operating profit and 3% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, ECS accounted for 4% of our revenue, 4% of our EBITDA, 4% of our operating profit and 4% of profit attributable to Petrofac Limited shareholders.

For the six months ended 30 June 2013, the IES division accounted for 15% of our revenue, 31% of our EBITDA, 21% of our operating profit and 19% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, our IES division accounted for 11% of our revenue, 22% of our EBITDA, 17% of our operating profit and 14% of our profit attributable to Petrofac Limited shareholders. IES was launched in 2011 as a single reporting segment and helps customers develop their resources either through the development of new fields or by enhancing production from mature reservoirs. The segment has three distinct but integrated service lines: • Developments develops, operates and maintains greenfield projects for resource holders. We will often co-invest in the development and receive returns based upon our performance; • Production Solutions improves production, operational efficiency and recovery from customers’ mature fields, which may involve investment in these field developments; and • Training Services develops and manages capability plans for customers and builds and operates training facilities. In 2012, Training Services managed 14 facilities in seven countries and delivered more than 200,000 “delegate days”, or days in which an individual was present at training.

Key Performance Indicators Our Directors and Senior Management regularly review KPIs, including revenue, EBITDA, operating profit, profit attributable to Petrofac Limited shareholders, profit margin and backlog. We believe that an understanding of these KPIs and the trends that may affect our performance on a consolidated basis is important to understanding our business and results of operations. Certain of these KPIs are non-IFRS financial measures, including EBITDA, operating profit and backlog. See “Presentation of Financial and Other Information—Non- IFRS Financial Information”.

Revenue Revenue comprises revenue from the rendering of services, sales of crude oil and gas and sales of processed hydrocarbons. Revenue is recognised to the extent that it is probable economic benefits will flow to us and the revenue can be reliably measured. See “—Critical Accounting Policies—Revenue Recognition”. At the consolidated group level, our revenue does not include intragroup sales as they are eliminated in the consolidation, while revenue for each reporting segment includes intragroup sales.

41 EBITDA EBITDA represents profit before tax adjusted for finance income, finance costs, depreciation, amortisation and impairment, as well as exceptional items such as the gain on the EnQuest demerger in 2010. It is used by our Senior Management in determining our core performance and we believe that it permits a more complete and comprehensive analysis of our operating performance. EBITDA is not a measure determined in accordance with IFRS and our use of the term EBITDA may vary from others in our industry. See “Presentation of Financial and Other Information—Non-IFRS Financial Information—EBITDA and Operating Profit”.

Operating Profit Operating profit represents profit before tax adjusted for finance income and finance costs as well as exceptional items such as the gain on the EnQuest demerger in 2010. It is used by our Senior Management in determining our core performance and we believe that it permits a more complete and comprehensive analysis of our operating performance. Operating profit is not a measure determined in accordance with IFRS and our use of the term operating profit may vary from others in our industry. See “Presentation of Financial and Other Information— Non-IFRS Financial Information—EBITDA and Operating Profit”.

Net Cash / (Debt) Net cash / (debt) comprises cash and short-term deposits, bank overdrafts, interesting bearing loans and borrowings (including the amounts utilised under our Revolving Credit Facility and Project Financing debt), adjusted to exclude unamortised debt acquisition costs and effective interest rate adjustments.

Profit Attributable to Petrofac Limited Shareholders Profit for the year attributable to Petrofac Limited shareholders represents our profit for the year, adjusted to exclude non-controlling interests.

Profit Margin Profit margin is profit attributable to Petrofac Limited shareholders represented as a percentage of revenue.

Backlog Backlog represents the estimated revenue attributable to the uncompleted portion of lump-sum EPC contracts and variation orders plus, with regard to engineering, operations, maintenance and IES contracts, the estimated revenue attributable to the lesser of the remaining term of the contract and five years. Backlog is not booked on IES contracts where we have entitlement to reserves. The value of a contract in a currency other than US dollars is booked at the applicable month-end exchange rate of the month in which the award is made and is revalued each month at the prevailing month-end exchange rate.

Backlog is a measure of our potential future revenue, and represents our estimate of a significant portion of anticipated future revenue. We accordingly consider backlog to be one of our KPIs. Completion of projects at the value reflected in the backlog is subject to a number of assumptions, risks and estimates, as well as the receipt of required governmental consents, permits, and regulatory clearances, which are the responsibility of the project owner and may be outside our control. There can be no assurance that all the revenue anticipated in our backlog will be realised in the timeframe expected or at all, or will result in profits. See “Risk Factors—Our revenue, cash flows, earnings and backlog may vary in any period depending on a number of factors, including achievement of milestones on major contracts”. Further, other companies may define the uncompleted portions of their order books differently, limiting the usefulness of backlog as a comparative measure. Backlog is not a measure determined in accordance with IFRS. See “Presentation of Financial and Other Information—Non-IFRS Financial Information—Backlog”.

Basis of Preparation of Financial Information The Financial Statements of the Group have been prepared in accordance with IFRS and applicable requirements of Jersey law.

The Financial Statements comprise the financial statements of the Group. The financial statements of our subsidiaries are prepared for the same reporting year as the Company and, where necessary, adjustments are made to the financial statements of our subsidiaries to bring their accounting policies into line with those used by us.

42 Subsidiaries are consolidated from the date on which control is transferred to us and cease to be consolidated from the date on which control is transferred out of our Group. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities. All intra-Group balances and transactions, including unrealised profits, are eliminated on consolidation.

Our consolidated non-controlling interests in subsidiaries are disclosed separately from our equity and income statement and non-controlling interests are allocated their share of total comprehensive income for the year even if this results in a deficit balance.

In 2011, we underwent an internal re-organisation, dividing the Group into the ECOM and IES divisions, which in turn operate through four reporting segments. See “—Segmental Reporting” below. As a result of this re-organisation, our comparative segmental information for 2010 was restated in our 2011 Consolidated Financial Statements to reflect the revised Group organisational structure.

Segmental Reporting We have four reporting segments for accounting purposes for the period under review: OEC, OPO, ECS and IES. Certain overheads, group financing and consolidation adjustments are managed at a corporate level and are not allocated to reporting segments. Prior to our internal re-organisation in 2011, we had operated through four reporting segments: Engineering and Construction, now the OEC reporting segment; Offshore Engineering and Operations, now the OPO reporting segment; Energy Developments; now the Developments service line; and Engineering, Training Services and Production Solutions, now split among the ECS, Training and Production Solutions service lines.

Principal Factors Affecting Our Results of Operations and Financial Position Principal factors affecting our results of operations during the periods under review (and those which are expected to affect our results of operations in the future) are discussed below:

Macroeconomic Factors Our revenue is highly dependent on a number of underlying macroeconomic growth factors that influence demand for oil and gas projects, in particular the level of investment by customers in oil and gas infrastructure and their operational expenditures. The level of activities is in turn largely driven by current and expected market prices for oil and gas which, together with other factors, such as cost of production and government fiscal policy determine the capital and operating expenditure budgets of our principal customers. These customer spending budgets have a greater impact on our revenue than short-term movements in the market prices for oil and gas which more directly affect the producing oil and gas assets which we have a stake in.

Over the long-term, we expect our revenue to be driven by an increased global demand for oil and gas which is expected to increase by over a third from 2011 to 2035 or 1.2% per annum on average according to the IEA. As a result of this increased demand the IEA is forecasting a significant growth in spending on oil and gas infrastructure with total capital expenditure of approximately US$19 trillion between 2012 and 2035 and approximately 50% of this investment being in our core markets of the UKCS, the Middle East, Africa, the CIS and the Asia Pacific region. Furthermore, operational expenditure is expected to increase significantly over time as the average cost per barrel of developing and maintaining new fields and maintaining existing mature producing fields is expected to increase particularly where production begins to decline.

The Middle East region where we have a strong presence is of critical importance to the world’s oil supply and it benefits from physically benign operating conditions, including shallow water and large fields which contribute to low operating costs. Notwithstanding our strategic aim to expand our global footprint, the Middle East is still expected to continue to play a very important role in the growth of our business.

Winning New Work and Investing in New Capital Projects Our future revenue and profit growth is heavily dependent on our ability to source potential new opportunities through our business development team and then bid competitively for new project awards which meet our internal margin or investment return requirements. Success in this area is a function of a number of factors, including our knowledge of the local market and customers based on previous project delivery experience, the technical quality of our service offering, our price competitiveness given our cost base, the type of commercial model being offered to the customer and our ability to meet in country staff content requirements for the project.

43 We have achieved order intake of US$5.2 billion for the six months ended 30 June 2013, US$7.5 billion for the year ended 31 December 2012, US$4.9 billion for the year ended 31 December 2011 and US$7.8 billion for the year ended 31 December 2010, which has historically created strong future revenue visibility through expectations and assumptions relating to our backlog. Backlog increased to US$14.3 billion as of 30 June 2013, having remained has remained broadly steady over the last three years, at US$11.8 billion as of 31 December 2012, US$10.8 billion as of 31 December 2011 and US$11.7 billion as of 31 December 2010. The decrease in backlog in 2011 compared with 2010 was the result of a net reduction in backlog in OEC due to increased progress across its portfolio of projects, which was only partially offset by an increase in backlog from the new IES division in that year. In the case of the IES division, the quality of investment decisions we make is important to the segment’s future success as significant amounts of capital are often invested by IES in long-term projects such as RSCs, PECs and energy infrastructure projects. These projects have very different payback period and rate of return profiles.

Long-term Customer Relationships We have a core group of customers for whom we regularly bid on business. Due to the size of many of our projects, the majority of our revenue in any year may be derived from a relatively small number of contracts. For the six months ended 30 June 2013, our top three contracts accounted for 31% of our total revenue while our top ten contracts accounted for 58% of our total revenue. In 2012, our top three contracts accounted for 42% of our total revenue while our top ten contracts accounted for 69% of our total revenue. In 2011, our top three contracts and top ten contracts accounted for 39% and 67%, respectively, of our total revenue. In 2010, our top three contracts and top ten contracts accounted for 38% and 63%, respectively, of our total revenue. Loss of a major customer would reduce the availability of repeat business from that customer and as a result, as part of our business strategy we are also heavily focused on building relationships with new customers. We believe that there are sufficient opportunities to increase our customer base to significantly reduce the risk of a loss of a major customer impacting on our results of operations.

Project Execution The profitability from our OEC and OCP long-term lump-sum contracts depends on delivering our projects on time and within established cost estimates. We rely on our extensive experience and robust cost estimation process to estimate accurately costs for projects in order to support our negotiations with customers. Our margins are dependent on accurate cost estimates at the time of bid and/or tender and cost control while the projects are being executed. Profitability also depends on our ability to enter into appropriately priced contracts for subcontracting labour and materials.

Our profitability, particularly within OEC, can also be dependent on negotiating additional payments for variations to the original contract scope. Although prices on our OEC contracts are generally fixed, we frequently encounter variations in our scope of work due to changes requested by the customer in relation to capacity, design and other specifications, which must be agreed to by both parties to the contract pursuant to the variation clauses. While we have successfully negotiated such variations on a number of contracts, it has at times been difficult to negotiate variations that preserve profit margins for the expected life of a given project.

A number of our OPO and IES contracts include performance-based compensation arrangements pursuant to which we are paid for our actual costs, with little or no guaranteed level of profits, and are eligible for incentive payments based on our achievement of a variety of objectives, including the level of operating costs, asset availability and health, safety and environmental matters. In some cases performance-based contracts have also evolved to include incentive payments based on overall field performance measures such as total cost of operation and production throughput.

The majority of our OPO and ECS contracts are reimbursable contracts, where costs are charged to the customers with a fixed margin added on top. These contracts may be for defined project scopes or on a “call-off” basis to provide engineering capability to the customer as and when required. As many of these contracts are time limited, these service lines are focused on demonstrating their value for money, quality and customer service to best position themselves for contract extensions or new scopes of work.

Within IES, the return on RSCs where we co-invest in the development of a field is often a function of a combination of KPIs relating to project delivery (e.g., meeting budget and delivery deadlines) as well as project operations (e.g., asset uptime, safety performance and hydrocarbon production rate). To ensure IES and its customers maximise the value derived from these contracts, IES focuses on efficiently managing the project development and operations and by having the best possible understanding of, and plan to exploit, the sub-surface dynamics of the oil or gas field.

44 For IES PECs, we are paid a tariff per barrel of production and returns are a function of increasing production above a production level agreed with the customer. To ensure value is maximised, IES deploys its subsurface technical team to understand a given reservoir so that it can create a development plan and maximise the production uplift. It also undertakes significant due diligence regarding the state of the surface facilities and creates plans to improve, repair or debottleneck these.

For IES PSCs, we take a direct interest in the production of a field and returns are a function of a combination of factors, including performing thorough due diligence on the sub-surface facilities, negotiating favourable financial terms with partners for sharing in production of the asset, identifying prospective new areas to drill in order to extend the life of the field, and managing production efficiently.

Revenue Recognition and Release of Provisions There will be a difference, which can be significant, between our revenue and cash flows for any particular reporting period depending on the mix, structure and progress of the contracts we have entered into. Revenue from our lump-sum contracts is recognised using the percentage-of-completion method of accounting, based on surveys of work performed once the outcome of a contract can be reliably estimated. This involves us recognising an increasing proportion of contract revenue and earnings as the contract progresses towards completion. For cost plus KPIs based contracts, where costs are charged to customers with a fixed margin and we may also receive payment based on delivery of agreed KPIs, failure to achieve certain pre-agreed and monitored performance targets will also potentially reduce contract revenues and profits. Our revenue and profits (or losses) are largely based on estimates of contract revenue, costs and profitability at completion and may not reflect actual revenue, profits or losses to date on the contract. In addition, although revenue and profits may be recognised for accounting purposes, these amounts do not represent actual cash received by us. When cash is received depends on the structure of each contract: under OEC contracts, for example, we may receive advance payments followed by payments on the achievement of set milestones, while under our OPO contracts we receive payment at regular intervals. See “—Critical Accounting Policies—Revenue Recognition”.

Furthermore, on final completion of long term lump-sum contracts, any remaining project contingency provisions are released to profit which can result in significant margin accretion during that period. Similarly, we set percentage of completion thresholds for each new contract, depending on an assessment of its risk level, before which we do not recognise any margin. Once the project crosses its initial progress based margin-recognition threshold, there is a one-off impact on its margin as the project moves from a costs-equal-to- revenue basis of accounting to a margin recognition method based on its cumulative progress percentage of the final estimated contract completion margin.

Disposal of Assets and Acquisition of Interests We have in the past and may from time to time divest of certain of our investments, realising exceptional gains on disposal. For example, in 2010 we demerged our interests in the Don area oil assets in the UKCS via a transfer to EnQuest PLC and realised a net gain of US$125 million. As a result, profit for the year in 2010 was US$558 million, compared with profit for the year of US$540 million in 2011. Before accounting for the EnQuest demerger, profit attributable to Petrofac Limited shareholders in 2010 was US$433 million in 2010, compared with profit attributable to Petrofac Limited shareholders of US$540 million in 2011. Such transactions are not part of our maintainable earnings but may sometimes drive significant one-off increases in profits for a given year.

Furthermore, although it is not a part of our long-term strategy, we have in the past and may from time to time acquire or dispose of equity interests in our joint ventures. For example, with effect from 1 January 2013, we agreed to increase our economic interest in Petrofac Emirates, our Abu Dhabi based joint venture with Mubadala Petroleum, to 75%. Petrofac Emirates was equity accounted as a 50% joint venture in the first half of 2012, whereas from 1 January 2013 it was consolidated as a 75% subsidiary following the acquisition of a further 25% interest from Mubadala Petroleum. As a result, we will report 100% of the revenue and backlog on all current and future Petrofac Emirates projects, with Nama Project Service’s 25% economic interest reported as profit for the year attributable to non-controlling interests. For the six months ended 30 June 2013, Petrofac Emirates accounted for US$139 million in revenue.

Taxation Our tax cost is a significant factor in determining the profit attributable to Petrofac Limited shareholders earned each year and the approach to effectively managing our tax position is to: • operate in accordance with the terms of the Petrofac Code of Conduct;

45 • act with integrity in all tax matters; • undertake all inter-company transactions on an arms-length basis; • work together with the tax authorities in jurisdictions that we operate in to build positive long-term relationships; • where disputes occur, address them promptly; and • manage tax in a pro-active manner to maximise value for our customers and shareholders.

We operate in a large number of jurisdictions and across a range of segments within the oil and gas industry. In most countries our operations will be taxed at the normal domestic corporation tax rate, but it is not unusual for licence holders on upstream oil and gas projects to be subject to either a separate or additional tax regime. Typically these regimes have a higher tax rate than the normal corporation tax rate for that country; for example, with our licence interests in the Block PM304 development in Malaysia and Chergui field in Tunisia, where the tax rates are 38% and 50% respectively, compared with the domestic corporation tax rates of 25% and 30%, respectively.

Our effective tax rate (“ETR”) is therefore significantly influenced by the mix and location of projects we undertake and whether or not they are subject to the oil and gas tax regimes specific to that country. In the regions where ECOM predominantly operates, the rates of corporation tax vary widely. For example, the UAE has a corporate tax rate of 0%, Oman has a rate of 12% and the United Kingdom a rate of 23% from 1 April 2013. In the countries where IES operates, normal corporation tax rates on non-licence holder contract tax rates range from 0% in the UAE to 16% in Romania, 25% in Malaysia and 30% in Mexico.

The application of this new standard impacts our financial position by eliminating proportionate consolidation of certain joint ventures. With the application of the new standard, the investment in those joint ventures is accounted for using the equity method of accounting. This standard became effective for annual periods beginning on or after 1 January 2013, and is applied retrospectively for joint arrangements held at the date of initial application. The impact of IFRS 11 on the year ended 31 December 2012 (which is reflected in the comparative period in the 2013 Interim Condensed Consolidated Financial Statements), is a reduction of revenue of US$84 million and a reduction in profit from operations of US$2 million as income from joint ventures is presented outside operating profit. Current assets and current liabilities are reduced by US$101 million and US$88 million, respectively, while the impact on non-current assets is a reduction of US$8 million. The reduction in net assets above results in recognition of additional investments in joint ventures of US$21 million which is included within non-current assets. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements beginning on page F-15 of the Financial Statements.

46 ICPI project. Subject to satisfactory execution of the first phase, a second phase, valued at over US$3.5 billion, is contemplated, to construct a polyethylene plant. The eventual scope for the IPCI project is expected to include the engineering, procurement, construction and commissioning of a gas plant, ethane cracker, gas pipelines, polyethylene plants and associated utilities and offsites in Kazakhstan.

On 11 September 2013, Petrofac Emirates, our Abu Dhabi based joint venture, received an advance payment of approximately US$290 million in respect of the Upper Zakum, UZ750 field development project in Abu Dhabi.

With effect from 1 January 2013, we agreed to increase our economic interest in Petrofac Emirates, our Abu Dhabi based joint venture with Mubadala Petroleum, to 75%. Mubadala Petroleum sold its shares in Petrofac Emirates to Nama Project Services. Nama Project Services is an affiliate of Nama Development Enterprises, a leading local service provider to the energy industry across the UAE. Nama Project Services will hold a 25% economic interest in Petrofac Emirates.

On 7 June 2013, we signed a MOU with KazMunaiGas Exploration Production JSC of Kazakhstan. The MOU allows the parties to explore opportunities to improve the efficiency of oil production and increase production from the mature Emba fields of KMG EP’s subsidiary EmbaMunaiGas JSC. Under the terms of the MOU, we intend to evaluate the Emba fields and to submit an offer for the long term improvement of the management and production in selected Emba fields in order to progress a potential PEC.

As of 31 August 2013, we had a net debt position of US$602 million consisting of US$939 million utilised under the Revolving Credit Facility, US$148 million of project financing for the Berantai FPSO, bank overdrafts of US$26 million and cash and short-term deposits of US$511 million.

Descriptions of Key Items from the Consolidated Income Statement Revenue Revenue comprises revenue from the rendering of services, sales of crude oil and gas and sales of processed hydrocarbons. Revenue is recognised to the extent that it is probable economic benefits will flow to us and the revenue can be reliably measured. See “—Critical Accounting Policies—Revenue Recognition”. At the consolidated group level, our revenue does not include intragroup sales as they are eliminated in the consolidation, while revenue for each reporting segment includes intragroup sales.

Cost of Sales Cost of sales represents the cost to us and our consolidated subsidiaries of providing integrated facilities solutions to the oil, gas and energy production and processing industries, including the subcontracting costs, equipment

47 hire costs, the cost of project equipment and machinery supplied under procurement contracts and depreciation charged on property, plant and equipment. Cost of sales also includes forward points and ineffective portions on derivatives designated as cash flow hedges, and losses on undesignated derivatives.

Selling, General and Administration Expenses Selling, general and administration expenses are comprised of staff costs, including wages and salaries, social security costs, pension costs, other long-term employee benefit costs and expense of share based payments; depreciation; amortisation of intangible assets; impairment of investments in associates and other operating expenses which consist primarily of office, travel, legal and professional and contracting staff costs.

Depreciation for all assets, other than oil and gas assets, is provided on a straight-line basis. Tangible oil and gas assets are depreciated on a field-by-field basis, using the unit-of-production method based on entitlement to proven and probable reserves, taking account of estimated future development expenditure relating to those reserves. No depreciation is charged on land or assets under construction.

Intangible assets with a finite life are amortised over their useful economic life using a straight-line method unless a better method reflecting the pattern in which the asset’s future economic benefits are expected to be consumed can be determined.

Other Income Other income includes foreign exchange gains, gains on disposal of non-current assets held for sale, a fair value gain on initial recognition of investments in associates, gains on disposal of investments in a joint venture, recovery of legal claims and fair value gains in associate company warrants.

Other Expenses Other expenses include foreign exchange losses, loss on fair value changes in associate company warrants and certain other expenses such as write off of unamortised debt costs.

Finance Costs Finance costs represent the cost of interest payable on long-term borrowings, short-term loans and overdrafts and the unwinding of discount on long-term benefit and decommissioning provisions.

Finance Income Finance income represents the interest receivable on bank deposits and the unwinding of discounts on long-term trade receivables from customers.

Share of Profits/(Losses) of Associates/Joint Ventures Share of profits/(losses) of associates/joint ventures represents our equity share of profits and losses incurred by our associates. Our associates are those entities in which we have significant influence.

Income Tax Expense Income tax expense represents the sum of current income tax and deferred tax.

Profit for the Year Attributable to Petrofac Limited Shareholders Profit for the year attributable to Petrofac Shareholders represents our profit for the year, adjusted to exclude non-controlling interests.

48 Results of Operations The following table sets out our consolidated income statement for the periods indicated:

The following tables show revenue, EBITDA, operating profit and profit attributable to Petrofac Limited shareholders by reporting segment for the periods indicated:

Six Months Ended 30 June Profit Attributable to Petrofac Limited Revenue EBITDA(1) Operating Profit(2) Shareholders(3) 2013 2012(4) 2013 2012(4) 2013 2012(4) 2013 2012(4) (unaudited) (US$ millions) Onshore Engineering & Construction ..... 1,610 2,333 224 318 190 299 171 251 Offshore Projects & Operations ...... 670 661 29 44 20 42 12 31 Engineering & Consulting Services ...... 180 103 9 7 6 4 6 5 Integrated Energy Services ...... 419 318 116 110 57 90 43 64 Corporate, consolidation & elimination . . . (85) (228) 27 (24) 22 (23) 11 (25) Total Group ...... 2,794 3,187 405 455 295 412 243 326

49 Year Ended 31 December Profit Attributable to Petrofac Limited Revenue EBITDA(1) Operating Profit(2) Shareholders(3) 2012 2011 2010(5) 2012 2011 2010(5) 2012 2011 2010(5) 2012 2011 2010(5) (audited) (unaudited) (unaudited) (audited) (US$ millions) Onshore Engineering & Construction ...... 4,358 4,146 3,254 580 585 472 540 554 438 479 463 373 Offshore Projects & Operations ...... 1,403 1,252 722 95 62 27 79 57 25 61 44 17 Engineering & Consulting Services ...... 248 208 173 36 40 26 30 33 20 29 31 21 Integrated Energy Services ..... 719 519 384 196 89 128 133 53 74 89 22 38 Corporate, consolidation & elimination ...... (404) (324) (179) (19) (16) (19) (24) (17) (18) (26) (20) (16) Total Group ...... 6,324 5,801 4,354 888 760 634 758 680 539 632 540 433

(1) EBITDA represents profit before tax adjusted for finance income, finance costs, depreciation, amortisation and impairment, as well as exceptional items such as the gain on the EnQuest demerger in 2010. (2) Operating profit represents profit before tax adjusted for finance income and finance costs as well as exceptional items such as the gain on the EnQuest demerger in 2010. (3) For 2010, profit attributable to Petrofac Limited shareholders excludes the gain on the EnQuest demerger of US$125 million. (4) Certain line items for the six months ended 30 June 2012 presented above have been restated as a result of the application of new IFRS 11—Joint Arrangements. See note 14 to the 2013 Interim Condensed Consolidated Financial Statements for details, including the impact of the restatement on such line items. (5) The segmental comparative 2010 figures were restated in our 2011 Consolidated Financial Statements to reflect our revised organisational structure. See “—Basis of Preparation of Financial Information”.

Results of Operations for the Six Months Ended 30 June 2013 and 30 June 2012 Revenue Revenue was US$2,794 million for the six months ended 30 June 2013, a decrease of US$393 million, or 12.3%, from revenue of US$3,187 million for the six months ended 30 June 2012. This decrease reflects the reduced activity on OEC projects that are nearing completion, the timing of recent new contract awards and the rephasing of the In Salah southern fields development project in Algeria in OEC which were partly offset by increased activity levels on the Mexican PECs within IES.

Onshore Engineering & Construction OEC revenue was US$1,610 million for the six months ended 30 June 2013, a decrease of US$723 million, or 31.0%, from revenue of US$2,333 million for the six months ended 30 June 2012. This decrease reflects reduced activity on projects that are nearing completion, the timing in respect of new contract awards and the temporary suspension of the In Salah southern fields development contract in Algeria

Offshore Projects & Operations OPO revenue was US$670 million for the six months ended 30 June 2013, an increase of US$9 million, or 1.4%, from revenue of US$661 million for the six months ended 30 June 2012. This increase was primarily due to the net effect of contracts awarded in the second half of 2012, including engineering and construction work for Apache in the UK North Sea, an offshore operations contract for South Oil Company in Iraq and an inspection, maintenance and repair contract for BP in Iraq which have increased activity levels in the first half of 2013, in addition to increased work carried out on the upgrade and modification of the FPF 1 for the Greater Stella Development in the UK North Sea and the refurbishment of the Bekok-C platform in Malaysia. These increases have been largely offset by lower activity levels in the six months ended 30 June 2013 compared with the corresponding period in 2012 on the OCP upgrade and modification work on the FPF 5 and the Berantai FPSO vessels.

Engineering & Consulting Services ECS revenue was US$180 million for the six months ended 30 June 2013, an increase of US$77 million, or 74.8%, from revenue of US$103 million for the six months ended 30 June 2012. This increase was primarily due

50 to significant activity on a training facility project in Malaysia for Petronas and the consolidation of RNZ Integrated Sdn Bhd (“RNZ”), a Malaysian engineering company following a transfer of management control to Petrofac in April 2013.

Integrated Energy Services IES revenue was US$419 million for the six months ended 30 June 2013, an increase of US$101 million, or 31.8%, from revenue of US$318 million for the six months ended 30 June 2012. This increase was primarily driven by a greater contribution from PECs, particularly Magallanes and Santuario in Mexico following our takeover of operation of the blocks in February 2012.

Cost of Sales Cost of sales was US$2,292 million for the six months ended 30 June 2013, a decrease of US$363 million, or 13.7%, from cost of sales of US$2,655 million for the six months ended 30 June 2012. This decrease was largely a result of a reduction in activity levels in the first half of the year, with our revenue decreasing by 12.3%.

Selling, General and Administrative Expenses Selling, general and administrative expenses were US$217 million for the six months ended 30 June 2013, an increase of US$41 million, or 23.3%, from selling, general and administrative expenses of US$176 million for the six months ended 30 June 2012. This increase was primarily due to increases in back office support functions head count, higher business development costs, Enterprise Resource Planning project related depreciation charges and data centre support costs after the system went live in most of the Group’s locations.

Other Income Other income was US$8 million for the six months ended 30 June 2013, a decrease of US$38 million, or 82.6%, from other income of US$46 million for the six months ended 30 June 2012. This decrease was primarily due to a gain of US$27 million realised in the first half of 2012 on the disposal of 75.2% of our interest in Petrofac FPF 1 Limited to Ithaca Energy Inc and a further US$9 million increase in the same period in the fair value of the remaining 24.8% interest held which was classified as an associate.

Other Expenses Other expenses were US$8 million for the six months ended 30 June 2013, a decrease of US$1 million, or 11.1%, from other expenses of US$9 million for the six months ended 30 June 2012. This decrease was primarily due to a US$2 million reduction in the valuation of our warrants over shares in our associate investment in Seven Energy in the first half of 2012, while there was no change in the first half of 2013. The decrease was partly offset by an increase in foreign exchange losses on translation in the six months ended 30 June 2013 compared with the corresponding period in 2012.

Finance Costs Finance costs were US$6 million for the six months ended 30 June 2013, an increase of US$4 million from finance costs of US$2 million for the six months ended 30 June 2012. This increase was primarily due to a significant increase in the Group’s net debt of US$603 million in the first half of 2013. This increase in our net debt was driven principally by further capital spend on IES projects and adverse movements in OEC and IES working capital balances, due in part to timing differences on OEC lump-sum contracts in the first half of 2013 compared with the first half of 2012.

Finance Income Finance income was US$11 million for the six months ended 30 June 2013, an increase of US$8 million from finance income of US$3 million for the six months ended 30 June 2012. This increase is due primarily to the unwinding of discounted long-term receivables on the Berantai RSC in the first half of 2013.

Share of Profits /(Losses) of Associates / Joint Ventures Our share of profits/(losses) of associates/joint ventures was US$10 million for the six months ended 30 June 2013, a decrease of US$9 million or 47.4%, compared with US$19 million for the six months ended 30 June 2012, primarily because the Petrofac Emirates joint venture was equity accounted as a 50% joint venture in the first half of 2012 with associated profits of US$21 million, whereas from 1 January 2013 it was consolidated as a

51 75% subsidiary following the acquisition of a further 25% interest from Mubadala Petroleum. See “—Recent Developments”. This decrease in the first half of 2013 was partly offset by a US$8 million net increase in the share of profits in the first half of 2013 from Seven Energy compared with the corresponding period in 2012 and additional profit contributions from the China Petroleum Petrofac Engineering Services Cooperatif and TTE Petrofac Limited associates in the first half of 2013.

Income Tax Expense Our income tax expense was US$58 million for the six months ended 30 June 2013, a decrease of US$31 million, or 34.8%, from income tax expense of US$89 million for the six months ended 30 June 2012, representing a Group ETR of 19.1% for the six months ended 30 June 2013 compared with an ETR of 21.5% for the six months ended 30 June 2012. This decrease in our ETR was due to a combination of the timing of profit recognition between the first and second halves of the respective years and changes in the mix of tax jurisdictions in which new contracts are underway, particularly in the OEC and IES reporting segments.

EBITDA EBITDA was US$405 million for the six months ended 30 June 2013, a decrease of US$50 million, or 11.0%, from EBITDA of US$455 million for the six months ended 30 June 2012. This decrease was primarily due to the net impact of a decrease in our operating profits of US$117 million and an increase in depreciation charges from US$43 million in the first half of 2012 to US$110 million in the first half of 2013 largely due to higher depreciation costs on the IES Mexican production enhancement assets.

Operating Profit Operating Profit was US$295 million for the six months ended 30 June 2013, a decrease of US$117 million, or 28.4%, from Operating Profit of US$412 million for the six months ended 30 June 2012. This decrease was primarily due to the expected significant weighting of 2013 profits towards the second half of the year for both the OEC and IES segments driven by timing differences in the profit recognition on major EPC contracts in OEC and IES projects compared with the corresponding six-month period in 2012.

Profit for the Period Attributable to Petrofac Limited Shareholders Profit for the period attributable to Petrofac Limited shareholders was US$243 million for the six months ended 30 June 2013, a decrease of US$83 million, or 25.5%, from profit for the year attributable to Petrofac Limited shareholders of US$326 million for the six months ended 30 June 2012. This decrease was primarily due to the gain on disposal of Petrofac FPF 1 Limited of US$36 million in the first half of 2012 (see “—Other Income” above) with the balance being largely attributable to a profit recognition timing difference nature in respect of major OEC and IES projects (see “—Operating Profit” above).

Onshore Engineering & Construction OEC’s profit for the period attributable to Petrofac Limited shareholders decreased by US$80 million, or 31.9%, from US$251 million for the six months ended 30 June 2012 to US$171 million for the six months ended 30 June 2013 with profit margins decreasing slightly from 10.8% for the six months ended 30 June 2012 to 10.6% for the six months ended 30 June 2013. The main drivers of the decrease in profit for the year attributable to Petrofac Limited shareholders were reduced activity on projects that are nearing completion, the timing in respect of new contract awards and the temporary suspension of the In Salah southern fields development contract in Algeria.

Offshore Projects & Operations OPO’s profit for the period attributable to Petrofac Limited shareholders decreased by US$19 million, or 61.3%, from US$31 million for the six months ended 30 June 2012 to US$12 million for the six months ended 30 June 2013 with profit margins decreasing from 4.7% for the six months ended 30 June 2012 to 1.8% for the six months ended 30 June 2013. The lower profit margins were largely due to high levels of activity from OCP in the first half of 2012, including the upgrade and modification of the FPF5 and FPSO Berantai. These projects completed in the second half of 2012, leading to a lower relative contribution in the first half of 2013 compared with the corresponding period in 2012.

Engineering & Consulting Services ECS’s profit for the period attributable to Petrofac Limited shareholders increased from US$5 million to for the six months ended 30 June 2012 to US$6 million for the six months ended 30 June 2013 with profit margins

52 decreasing from 4.9% for the six months ended 30 June 2012 to 3.3% for the six months ended 30 June 2013. This profit margin reduction was largely due to below-average profit margins being earned on a training facility project in Malaysia.

Integrated Energy Services IES’s profit for the period attributable to Petrofac Limited shareholders decreased by US$21 million, or 32.8%, from US$64 million for the six months ended 30 June 2012 to US$43 million for the six months ended 30 June 2013 with profit margins decreasing from 20.1% for the six months ended 30 June 2012 to 10.3% for the six months ended 30 June 2013. The main reasons for the decrease in profit margin were that the first half of 2012 benefited from a gain on disposal of FPF 1 Limited of US$36 million (see “—Other Income” above for details) and after adjusting for this gain the profit margin in the first six months of 2012 were 8.8% compared with 10.3% for the first half of 2013. This adjusted 1.5% improvement in profit margin has been largely driven by higher activity levels generated from the Mexican PECs in the first half of 2013 as we improved production levels on the Magallanes and Santuario blocks and took over field operations on the Panuco contract area in March 2013.

Results of Operations for 2012 and 2011 Revenue Revenue was US$6,324 million in 2012, an increase of US$523 million, or 9.0%, from revenue of US$5,801 million in 2011. This increase was primarily due to increased activity levels across the Group in 2012, particularly within IES which grew in revenue by 38.6% and the OPO reporting segment which grew in revenue by 12.1% (see below for further details).

Onshore Engineering & Construction OEC revenue was US$4,358 million in 2012, an increase of US$212 million, or 5.1%, from revenue of US$4,146 million in 2011. This increase reflected an increase in physical project completion progress in 2012 compared with 2011. Specifically in 2012, five projects contributed 75% of OEC revenue: the South Yoloten gas plant in Turkmenistan, the Asab onshore oil field development in Abu Dhabi, the El Merk gas processing facility, the In Salah southern fields development in Algeria and the gas sweetening facilities project in Qatar.

Offshore Projects & Operations OPO revenue was US$1,403 million in 2012, an increase of US$151 million, or 12.1%, from revenue of US$1,252 million in 2011. This increase was primarily due to increased support activity levels on long-term operations management contracts, additional physical progress on the Laggan-Tormore project, and increased physical progress on offshore capital projects relating to the West Desaru and Berantai projects.

Engineering & Consulting Services ECS revenue was US$248 million in 2012, an increase of US$40 million, or 19.1%, from revenue of US$208 million in 2011. This increase was primarily due to having secured a number of conceptual and FEED studies during the year, including a FEED study on behalf of Rialto Energy and Société Nationale d’Opérations Pétrolières de la Côte D’Ivoire.

Integrated Energy Services IES revenue was US$719 million in 2012, an increase of US$200 million, or 38.6%, from revenue of US$519 million in 2011. This increase was primarily due to substantial progress made on the Berantai RSC and the commencement of the Magallanes and Santuario PECs.

Cost of Sales Cost of sales was US$5,244 million in 2012, an increase of US$403 million, or 8.3%, from cost of sales of US$4,841 million in 2011. This increase was largely the result of higher depreciation charges on increased IES related capital expenditure compared with 2011.

Selling, General and Administrative Expenses Selling, general and administrative expenses were US$359 million in 2012, an increase of US$76 million, or 27.0%, from selling, general and administrative expenses of US$283 million in 2011. This increase was primarily due to an increase in staff headcount, as well as increases in other operating expenses such as office, travel, legal and professional and contracting staff costs that were required to support our growth during 2012.

53 Other Income Other income was US$65 million in 2012, an increase of US$53 million, or 441.7%, from other income of US$12 million in 2011. This increase was primarily due to a gain of US$36 million in 2012 in relation to the disposal by IES of a 75.2% interest in FPF1 Limited to Ithaca Energy Inc and subsequent initial recognition of the residual interest in FPF1 Limited as an associate, a gain of US$6 million on disposal of IES’s joint venture interest in the Kyrgyzstan Petroleum Company refinery and the recovery of US$6 million from a long-standing legal claim in the United States.

Other Expenses Other expenses were US$20 million in 2012, an increase of US$15 million, or 300.0%, from other expenses of US$5 million in 2011. This increase was primarily due to an increase in foreign exchange losses on translation of US$7 million in 2012 compared with 2011, and a US$6 million decrease in the fair value of the Seven Energy International Limited (“Seven Energy”) associate warrants as of 31 December 2012. These associate warrants are warrants over shares we own in our associate investment in Seven Energy. The warrants were earned by provision of our services to Seven Energy, and are fair valued each year, resulting in gains or losses each year as the valuation changes.

Finance Costs Finance costs were US$5 million for 2012, a decrease of US$2 million, or 28.6%, from finance costs of US$7 million in 2011. This decrease was primarily due to the early repayment of long-term loans during the year as well as lower average short-term overdraft balances during 2012 compared with 2011.

Finance Income Finance income was US$12 million in 2012, an increase of US$4 million, or 50.0%, from finance income of US$8 million in 2011. This increase is due to the unwinding of the discounted element of a long-term trade receivable due in respect of the Berantai RSC amounting to US$7 million which has been partly offset by lower bank interest income earned on significantly lower average surplus cash balances held by us during 2012 compared with the prior year.

Share of Profits/(Losses) of Associates/Joint Ventures Share of profits/(losses) of associates/joint ventures was US$8 million in 2012, an increase in such losses of US$4 million, or 100%, from share of losses of associates of US$4 million in 2011, primarily due to increased trading losses incurred by Seven Energy during 2012.

Income Tax Expense Our income tax expense was US$135 million in 2012, a decrease of US$6 million, or 4.3%, from income tax expense of US$141 million in 2011, representing a Group ETR of 17.7% in 2012 compared with an ETR of 20.7% in 2011. This decrease in our 2012 ETR by 3.0% was due to a number of factors, including the net release of prior year tax provisions held in respect of income taxes, the recognition of previously unrecognised tax losses and a change since 2011 in the tax jurisdictions in which profits were earned.

EBITDA EBITDA was US$888 million in 2012, an increase of US$128 million, or 16.8%, from EBITDA of US$760 million in 2011. This increase was primarily due to an increase in operating profits in 2012 across our segments compared with 2011, as well as an increase in depreciation and amortisation compared with 2011 particularly in IES.

Operating Profit Operating Profit was US$758 million in 2012, an increase of US$78 million, or 11.4%, from Operating Profit of US$680 million in 2011. This increase was primarily due to substantial increases in revenue in 2012 compared with 2011.

54 Profit for the Year Attributable to Petrofac Limited Shareholders Profit for the year attributable to Petrofac Limited shareholders was US$632 million in 2012, an increase of US$92 million, or 17.0%, from profit for the year attributable to Petrofac Limited shareholders of US$540 million in 2011. This 17% increase was primarily due to higher business activity levels across all four reporting segments of the Group and an overall improvement in the Group’s profit margins earned from 9.3% in 2011 to 10.0% in 2012.

Onshore Engineering & Construction OEC’s profit for the year attributable to Petrofac Limited shareholders increased by US$16 million, or 3.5%, from US$463 million in 2011 to US$479 million in 2012 with profit margins decreasing slightly from 11.2% in 2011 to 11.0% in 2012. The main drivers of the increase in profit for the year attributable to Petrofac Limited shareholders were increased revenue in 2012 compared with 2011 and major profit margin contributions from the South Yoloten gas plant in Turkmenistan, El Merk central processing facility and the In Salah Gas projects in Algeria. The increase in profit margin from these projects was offset in part by higher proposal costs on increased bidding activity during 2012 and an increase in overheads required to support the OEC business growth.

Offshore Projects & Operations OPO’s profit for the year attributable to Petrofac Limited shareholders increased by US$17 million, or 39%, from US$44 million in 2011 to US$61 million in 2012 with profit margins increasing from 3.5% in 2011 to 4.3% in 2012. The improved profitability and higher profit margins were largely attributable to the first time recognition of progress based profit on the Laggan-Tormore gas plant project in the Shetlands and significant, higher profit margin contributions from a new vessel modification and upgrade prior to deployment on the West Desaru field in Malaysia, a new refurbishment of the Bekok-C platform in Malaysia, an inspection, maintenance and repair contract for BP in Iraq and from the Apache UKCS engineering and construction contract.

Engineering & Consulting Services ECS’s profit for the year attributable to Petrofac Limited shareholders decreased by US$2 million, or 6.5%, from US$31 million in 2011 to US$29 million in 2012 with profit margins also reducing from 14.8% in 2011 to 11.7% in 2012. These decreases were mainly attributable to the recognition in 2011 of a US$6 million gain in the fair value of share warrants held in our associate investment in Seven Energy compared with a US$6 million loss in the value of these warrants in 2012.

Integrated Energy Services IES’s profit for the year attributable to Petrofac Limited shareholders increased by US$67 million, 304.5%, from US$22 million in 2011 to US$89 million in 2012 with profit margins increasing from 4.4% in 2011 to 12.4% in 2012. The main reasons for the significant increase in profitability and profit margin growth were the gain of US$36 million on the sale of 75.2% of FPF1 Limited to Ithaca Energy Inc and the subsequent initial recognition of the residual interest in FPF1 Limited as an associate, the first time profit recognition on the Berantai RSC and the commencement of work on the Magallanes and Santuario PECs in Mexico.

Results of Operations for 2011 and 2010 Revenue Revenue was US$5,801 million in 2011, an increase of US$1,447 million, or 33.2%, from revenue of US$4,354 million in 2010. This increase was primarily due to strong growth in the operating activity levels across our reporting segments.

Onshore Engineering & Construction OEC revenue was US$4,146 million in 2011, an increase of US$892 million, or 27.4%, from revenue of US$3,254 million in 2010. This increase was driven by physical progress made on major lump-sum EPC contracts in 2011, in particular, on the Asab oil field development in Abu Dhabi and the second phase of the South Yoloten project in Turkmenistan.

Offshore Projects & Operations OPO revenue was US$1,252 million in 2011, an increase of US$530 million, or 73.3%, from revenue of US$722 million in 2010. This increase was primarily due to strong support activity levels across the segment but

55 particularly from the offshore capital projects such as the Sepat Development and the FPSO vessels, Berantai FPSO, upgrade, the Sajaa gas plant Duty Holder contract, the Laggan-Tormore gas plant and the Apache UKCS engineering and construction contract.

Engineering & Consulting Services ECS revenue was US$208 million in 2011, an increase of US$35 million, or 20.0%, from revenue of US$173 million for 2010. This increase was primarily due to increased engineering support levels from the reporting segment’s operations in India on major OEC projects.

Integrated Energy Services IES revenue was US$519 million in 2011, an increase of US$135 million, or 35.0%, from revenue of US$384 million for 2010. This significant increase was primarily due to the commencement of the Berantai RSC in Malaysia and an increased contribution from the Ticleni PEC in Romania during the course of 2011.

Cost of Sales Cost of sales was US$4,841 million in 2011, an increase of US$1,246 million, or 34.7%, from cost of sales of US$3,595 million in 2010. This increase was primarily driven by the increase in overall Group activity levels during 2011 and in particular the ramp up of activity levels on lump-sum EPC contracts such as Asab in Abu Dhabi and South Yoloten in Turkmenistan.

Selling, General and Administrative Expenses Selling, general and administrative expenses was US$283 million in 2011, an increase of US$61 million, or 27.8%, from selling, general and administrative expenses of US$222 million in 2010. This increase was primarily due to higher staff costs as our reporting segments hired additional employees to support increased trading activity levels and increased bonuses and annual salary increments paid to existing staff.

Gain on EnQuest Demerger In 2010, we realised a one-off capital gain of US$125 million on the demerger of our interests in the Don area oil assets via a transfer of three of our subsidiaries, Petrofac Energy Developments Limited, Petrofac Energy Developments Oceania Limited and PEDL Limited to EnQuest PLC for a deemed consideration for accounting purposes of US$553 million, which was settled by the issue of EnQuest PLC shares directly to the Company’s shareholders.

Other Income Other income was US$12 million in 2011, an increase of US$7 million, or 441.7%, from other income of US$5 million in 2010. This increase was primarily due to an increase in the fair value of Seven Energy warrants on revaluation at 31 December 2011 of US$6 million as well as higher foreign exchange gains arising from conversion of sterling denominated profits into our reporting currency of US dollars.

Other Expenses Other expenses were US$5 million in 2011, an increase of US$1 million, or 23.4%, from other expenses of US$4 million in 2010. This increase was primarily due to relatively small increases in bank fees and foreign exchange losses on converting surplus sterling based cash to US dollars for our reporting purposes.

Finance Costs Finance costs were US$7 million in 2011, an increase of US$2 million, or 36.4%, from finance costs of US$5 million in 2010. This increase was primarily due to an increase during 2011 in the use of short-term overdrafts and higher unwinding of the discount factor on long-term provisions for end of service benefits to which all UAE staff are entitled to by law, based on the number of years in service. As a result of the long-term nature of the benefits, we apply a discount factor which unwinds each year through finance costs. In addition, the decommissioning of certain IES assets contributed to finance costs in 2011.

Finance Income Finance income was US$8 million in 2011, a decrease of US$2 million, or 21.6%, from finance income of US$10 million in 2010. This decrease was primarily due to lower bank interest rate yields on surplus cash deposits held in US dollars and euro as average surplus cash balances during 2011 were higher than in 2010.

56 Share of Profits/(Losses) of Associates/Joint Ventures Our share of profits/(losses) of associates/joint ventures was US$4 million in 2011, from share of losses of associates of zero in 2010. This change was the result of the increase of our ownership interest in Seven Energy to 20%, so that the asset could no longer be classified as an asset held for sale and we accordingly incurred a US$3 million share of Seven Energy’s consolidated losses in 2011. In addition, losses incurred by Gateway Storage Company of US$1 million contributed to the increase in our share of losses of associates in 2011 compared with 2010.

Income Tax Expense Income tax expense was US$141 million in 2011, an increase of US$30 million, or 27.5%, from income tax expense of US$111 million in 2010. Our ETR in 2011 was 20.7% compared with 16.5% in 2010 and this increase in our ETR was almost entirely driven by the fact that in 2010 no chargeable gain arose on the EnQuest demerger transaction which generated a tax free profit of US$125 million. Excluding the demerger gain, our 2010 ETR would have been 20.3% and the small remaining increase in the adjusted year on year ETR was attributable to changes during 2011 in tax jurisdictions in which Group profits were earned.

EBITDA EBITDA was US$760 million in 2011, an increase of US$126 million, or 19.9%, from EBITDA of US$634 million in 2010. This increase was primarily due to substantial increases in operating profits in 2011 compared with 2010 which was partially offset by a decrease in depreciation and amortisation compared with 2010.

Operating Profit Operating profit was US$680 million in 2011, an increase of US$141 million, or 26.2%, from operating profit of US$539 million in 2010. This increase was primarily due to substantial increases in revenue in 2011 compared with 2010.

Profit for the Year Profit for the year was US$540 million in 2011, a decrease of US$18 million, or 3%, from profit for the year of US$558 million in 2010. This decrease was primarily due to the one-off gain on the EnQuest demerger of US$125 million in 2010, which was partially offset by the other factors described above in “—Results of Operations for 2011 and 2010”.

Profit for the year Attributable to Petrofac Limited Shareholders Excluding the gain on the EnQuest demerger in 2010, profit for the year attributable to Petrofac Limited shareholders was US$540 million in 2011, an increase of US$107 million, or 25%, from US$433 million in 2010. This increase was primarily due to higher business activity levels across all four reporting segments of the Group, particularly in OEC and OPO, despite an overall reduction in the Group’s profit margins earned from 9.9% in 2010 to 9.3% in 2011 principally due to a decrease in profit margins in the OEC and IES reporting segments.

Onshore Engineering & Construction OEC’s profit for the year attributable to Petrofac Limited shareholders increased by US$90 million, or 24%, from US$373 million in 2010 to US$463 million in 2011 with profit margins decreasing slightly from 11.5% in 2010 to 11.2% in 2011. The main drivers of the increase in profit for the year attributable to Petrofac Limited shareholders were profit margin contributions from the Asab oil field development in Abu Dhabi, the South Yoloten gas plant project in Turkmenistan, the El Merk central processing facility in Algeria, the GASCO NGL train in Abu Dhabi and the Majnoon early production facility contract in Iraq. The higher profit margin percentage in 2010 was attributable to the completion of a number of major projects during the year and the first time recognition of profit margin in 2010 on some contracts awarded in 2009.

Offshore Projects & Operations OPO’s profit for the year attributable to Petrofac Limited shareholders increased by US$27 million, or 158.8%, from US$17 million in 2010 to US$44 million in 2011 with profit margins increasing from 2.4% in 2010 to 3.5% in 2011. The improved profitability and higher profit margins were largely attributable to the first time

57 recognition of profits from the Sepat development and the Berantai FPSO upgrade in Malaysia and significant margin contributions from the Sajaa gas plant Duty Holder contract in Sharjah UAE and from the release of provisions made following completion of a long-term maintenance services contract in Kuwait.

Engineering & Consulting Services ECS’s profit for the year attributable to Petrofac Limited shareholders increased by US$10 million, or 47.6%, from US$21 million in 2010 to US$31 million in 2011 with profit margins also increasing from 12.2% in 2010 to 14.8% in 2011. These increases were largely attributable to US$6 million of fair value gains on the associate investment in Seven Energy in Nigeria, higher activity levels in our Indian engineering offices which supported an increased workload in OEC and increased chargeable man hours in our Woking engineering office that was supporting a number of ECOM and IES projects, as well as providing additional services for external customers.

Integrated Energy Services IES’s profit for the year attributable to Petrofac Limited shareholders decreased by US$16 million, or 42.1%, from US$38 million in 2010 to US$22 million in 2011, with profit margins decreasing from 9.9% in 2010 to 4.4% in 2011. The main reasons for the significant decrease in profitability and profit margin percentage during 2011 were the loss of contribution from Dubai Petroleum as a result of our transition from a service operator role to a technical services agreement, lower oil production from our Block PM304 development in offshore Malaysia and the loss of profits arising from the demerger of the North Sea Don assets in April 2010, which were partly offset by a profit contribution in relation to the vesting of Seven Energy warrants and income from the leasing of the new floating production facility, FPF3, in Thailand.

Liquidity and Capital Resources Historically, we have been cash generative in particular from our lump-sum onshore EPC activities but more recently with the strategic focus shifting towards the rapid expansion of the IES division as a major new engine for growth, our business as a whole has become more capital intensive. As a result, during 2012 we utilised for the first time a mixture of our operating cash flow resources and external funding to meet the costs of the IES capital investment programme and have continued to utilise external funding during the first eight months of 2013. Our Senior Management monitors our liquidity requirements through the use of two year rolling cash flow forecasts, which are prepared and reviewed on a monthly basis, and via the Group’s annual five year strategic planning process.

Our principal sources of liquidity include cash from operations, cash and cash equivalents and borrowings under the Group’s US$1,200 million committed revolving credit facility (the “Revolving Credit Facility”). As of 31 December 2012, we had total financial debt of US$292 million, representing the US$303 million utilised under the Revolving Credit Facility after amortised debt costs of US$11 million, and cash and cash equivalents of US$557 million. As of 31 August 2013, we had a net debt position of US$602 million consisting of US$939 million utilised under the Revolving Credit Facility, project financing of US$148 million for the Berantai FPSO, bank overdrafts of US$26 million and cash and short-term deposits of US$511 million. The cash outflow since 31 December 2012 was predominately due to investment in IES projects and the unwinding of cash advances and working capital outflows on OEC projects. We expect to remain in a net debt position in the medium term driven by the ongoing deployment of cash on IES projects and initial investment in our offshore strategy.

Utilising our anticipated operating cash flow surpluses and our Revolving Credit Facility, we believe that we have sufficient working capital available to meet our liabilities as they fall due and to continue to operate for the foreseeable future.

58 Cash Flows The following table sets out information on our consolidated statement of cash flows for the periods indicated:

Six Months Ended Year Ended 30 June 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Profit before tax ...... 300 413 765 681 668 Gain on EnQuest demerger ...... — — — — (125) Non-cash adjustments to reconcile profit before tax to net cash flows: Depreciation, amortisation, impairment and write off ...... 110 43 130 80 96 Share-based payments ...... 7 13 26 23 15 Difference between other long-term employment benefits paid and amounts recognised in the income statement ...... 4 9 11 9 6 Net finance income ...... (5) (1) (7) (1) (5) Loss/(gain) on fair value changes in Seven Energy warrants ...... — 4 6 (6) — Gain arising from sale of vessel under a finance lease ...... (22) — — — — Gain on disposal of investment in a joint venture ...... — — (6) — — Share of (profits)/losses of associates/joint ventures ...... (10) (19) 8 4 — Gain on disposal of non-current asset held for sale ...... — (27) (27) — — Fair value gain on initial recognition of investment in associate .... — (9) (9) — — Gain on disposal of intangible assets ...... — — — — (2) Debt acquisition costs written off ...... — — 3 — — Other non-cash items, net ...... 4 4 7 6 13 388 430 907 796 666 Working capital adjustments: Trade and other receivables ...... 160 55 (549) (301) (267) Work in progress ...... (86) (384) (44) 192 (470) Due from related parties ...... (18) 89 77 (99) 18 Inventories ...... (11) (12) (16) (3) (3) Other current financial assets ...... 42 (1) (68) 17 (13) Trade and other payables ...... (325) (49) 253 735 168 Billings in excess of cost and estimated earnings ...... 19 (115) (61) 211 (283) Accrued contract expenses ...... (233) (205) (525) (7) 439 Due to related parties ...... (33) 35 15 12 (45) Other current financial liabilities ...... — (1) — — 6 (97) (158) (11) 1,553 216 Long-term receivable from a customer ...... (76) (204) (300) (130) — Other non-current items, net ...... 6 3 (4) — (9) Cash (used in)/generated from operating activities ...... (167) (359) (315) 1,423 207 Interest paid ...... (5) — (3) (3) (2) Income taxes paid, net ...... (37) (42) (83) (157) (99) Net cash flows (used in)/from operating activities ...... (209) (401) (401) 1,263 106 Investing activities Purchase of property, plant and equipment ...... (201) (149) (397) (420) (115) Acquisition of subsidiaries, net of cash acquired ...... 62 (15) (20) — (15) Payment of contingent consideration on acquisition ...... — — (1) (16) — Purchase of other intangible assets ...... (16) — (7) (6) — Purchase of intangible oil and gas assets ...... (44) (54) (165) (40) (16) Cash outflow on EnQuest demerger (including transaction costs) ...... — — — — (18) Investments in associates ...... — — (25) (50) (8) Dividend received from a joint venture ...... 2 — — — — Purchase of available-for-sale financial assets ...... — — (101) Proceeds from disposal of property, plant and equipment ...... — — 1 — 3 Proceeds from disposal of non-current asset held for sale ...... — 60 60 — — Proceeds from sale of intangible assets ...... — — — — 6 Proceeds from disposal of an investment in a joint venture ...... — — 5 — — Interest received ...... 1 3 5 9 10 Net cash flows used in investing activities ...... (196) (155) (544) (523) (254)

59 Six Months Year Ended Ended 30 June 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Financing activities Interest bearing loans and borrowings obtained, net of debt acquisition cost ...... 568 — 291 — — Repayment of interest-bearing loans and borrowings ...... (9) (11) (50) (19) (32) Treasury shares purchased ...... (45) (76) (76) (49) (37) Equity dividends paid ...... (148) (128) (201) (159) (132) Net cash flows from/(used in) financing activities ...... 366 (215) (36) (227) (201) Net (decrease)/ increase in cash and cash equivalents ...... (39) (771) (981) 513 (349) Net foreign exchange difference ...... 1 (11) 3 (12) (8) Cash and cash equivalents at 1 January ...... 525 1,535 1,535 1,034 1,391 Cash and cash equivalents at period end ...... 485 753 557 1,535 1,034

Net Cash Flows (Used in)/from Operating Activities Our net cash flows (used in)/from operating activities was an outflow of US$209 million for the six months ended 30 June 2013 from an outflow of US$401 million for the six months ended 30 June 2012. This variance was primarily due to favourable movements in the OEC contract work in progress balances and a reduction in the first half of 2013 in the adverse movements in the long-term receivable from the Berantai RSC and the Greater Stella Area project compared to the corresponding period in 2012.

Our net cash flows (used in)/from operating activities was an outflow of US$401 million for the year ended 31 December 2012, from an inflow in net cash flows (used in)/from operating activities of US$1,263 million for the year ended 31 December 2011 (see below for details). This change was primarily due to adverse movements in working capital during 2012 in particular trade and other receivables, accrued contract expenses, the long-term receivable on the Berantai RSC and the Greater Stella Area Development and the unwinding of customer advances on long-term lump-sum EPC contracts component of trade and other payables.

Our net cash flows from operating activities was an inflow of US$1,263 million for the year ended 31 December 2011, from an inflow in net cash flows (used in)/from operating activities of US$106 million for the year ended 31 December 2010. This change was primarily due to favourable movements in working capital relating to work in progress, the significant increase in customer advances on long-term lump-sum EPC contracts within trade and other payables, timing differences in billings in excess of cost and estimated earnings on EPC contracts, partly offset by working capital outflows relating to trade and other receivables due from related parties and the long- term receivable on the Berantai RSC.

Net Cash Flows Used in Investing Activities Our net cash flows used in investing activities was an outflow of US$196 million for the six months ended 30 June 2013, from an outflow in net cash flows used in investing activities of US$155 million for the six months ended 30 June 2012. Net cash flows used in investing activities for the six months ended 30 June 2013 largely related to capital expenditure of US$220 million on IES projects less US$62 million of cash recognised on the consolidation of Petrofac Emirates and RNZ.

Our net cash flows used in investing activities was an outflow of US$544 million for the year ended 31 December 2012, from an outflow in net cash flows used in investing activities of US$523 million for the year ended 31 December 2011. Net cash flows used in investing activities for the year ended 31 December 2012 largely related to capital expenditure on IES projects of US$433 million consisting mainly of the acquisition and upgrade of floating production vessels, field development costs in relation to PECs in Mexico and Romania and development expenditure on Block PM304 offshore in Malaysia, a further US$127 million of capital expenditure on assets under construction, leasehold improvements and office furniture and equipment and an investment of a further US$25 million in Seven Energy. These capital outflows were partly offset by US$60 million of proceeds realised from the disposal of 75.2% of our interest in FPF1 Limited to Ithaca Energy Inc.

60 Our net cash flows used in investing activities was an outflow of US$523 million for the year ended 31 December 2011, from an outflow in net cash flows used in investing activities of US$254 million for the year ended 31 December 2010. This increased net cash outflow for the year ended 31 December 2011 was primarily due to capital expenditure on IES projects of US$352 million predominantly in relation to the acquisition and upgrade of floating production vessels, other Group capital expenditure of US$108 million on projects, temporary camp facilities, site-based vehicles and office equipment and furniture and US$50 million of further investment in Seven Energy.

Net Cash Flows From/(Used) in Financing Activities Our net cash flows from financing activities was an inflow of US$366 million for the six months ended 30 June 2013, from an outflow in net cash flows used in financing activities of US$215 million for the six months ended 30 June 2012. The inflow in the six months ended 30 June 2013 was primarily due to US$568 million of interest bearing loans net of debt costs being obtained from a combination of drawing down US$417 million on the existing Revolving Credit Facility and raising project financing for the Berantai FPSO of US$153 million.

Our net cash flows used in financing activities was an outflow of US$36 million for the year ended 31 December 2012, from an outflow in net cash flows used in financing activities of US$227 million for the year ended 31 December 2011. The outflow during 2012 was primarily due to the net effect of proceeds received from the drawing down of US$291 million (net of debt acquisition costs) on the Revolving Credit Facility, the repayment of US$50 million of long-term Group borrowings, the purchase of treasury shares for Group share scheme awards at a cost of US$76 million and the payment of US$201 million of dividends to shareholders.

Our net cash flows used in financing activities was an outflow of US$227 million for the year ended 31 December 2011, from an outflow in net cash flows used in financing activities of US$201 million for the year ended 31 December 2010. The outflow during 2011 was primarily due to the payment of US$159 million in respect of dividends to shareholders, the purchase of treasury shares for Group share scheme awards at a cost of US$49 million and the repayment of US$19 million of long-term Group borrowings.

Indebtedness Interest-bearing Loans and Borrowings As of 30 June 2013, we had total interest-bearing loans and borrowings after amortised debt costs of US$908 million. The following table sets out a breakdown of our interest-bearing loans and borrowings for the periods indicated:

As of 30 June As of 31 December 2013 2012(1) 2012 2011 2010 (unaudited) (audited) (US$ millions) Current: Bank overdrafts ...... 53 37 57 37 29 Other loans: Current portion of project financing ...... 20 — — — — Current portion of term loan 1 ...... — 19 — 17 14 Current portion of term loan 2 ...... — 9 — 7 4 Total current loans ...... 73 65 57 61 47 Non-current: Revolving Credit Facility ...... 720 — 303 — — Project financing ...... 128 — — — — Term loan 1 ...... — 2 — 12 30 Term loan 2 ...... — 3 — 7 14 Total non-current loans ...... 848 5 303 19 44 Debt acquisition costs net of accumulated amortisation and effective interest rate adjustments ...... (13) (3) (11) (3) (4) Total ...... 908 67 349 77 87

61 Bank Overdrafts Bank overdrafts are drawn down in US dollars and sterling denominations to meet our working capital requirements and are repayable on demand.

Term Loans Our two term loans were repaid in full in 2012 using surplus cash and as of 31 August 2013 we have no term loans outstanding.

Project Financing In May 2013, our joint venture project, Berantai Floating Production Limited (“BFPL”), entered into a US$300 million senior secured term loan facility (the “BFPL Facility”) with a syndicate of four banks to refinance the cost of obtaining and developing the Berantai FPSO. Our wholly owned subsidiary Petrofac Energy Developments Sdn Bhd (“PED”) owns a 51% share of BFPL, and Sapura Energy Ventures Sdn Bhd and Kencana Energy Sdn Bhd (together with PED, the “Sponsors”) own a 49% share of BFPL.

The loan under the BFPL Facility, which was advanced in full in May 2013, will be repaid in installments on a quarterly basis and has a final maturity date of October 2019. The BFPL Facility contains a debt service coverage ratio financial covenant of not less than 1.15:1, which applies only to BFPL and not to any other members of the Group. Interest on the loan is calculated at LIBOR plus a margin of 2.70%. Underlying LIBOR has been hedged at 1.675% for the duration of the loan. In addition, the sum of the borrower paid arrangement, co-ordinating, facility agent and security arrangement fees have been capitalised and are being amortised over the term of the loan.

Under the BFPL Facility, the Sponsors undertake, inter alia, to: (i) maintain ownership of one hundred percent of the shares of BFPL and (ii) not to agree to a price for the sale of the Berantai FPSO, or to sell the Berantai FPSO, for an amount less than the outstanding BFPL Facility loan at the time of such sale.

The BFPL Facility is secured by pledges of property, right, title, interest and benefit in and to the Berantai FPSO and project accounts of BFPL and all Sponsors’ shares in BFPL and, if applicable, all financial indebtedness owed by BFPL to the Sponsors.

The BFPL Facility is governed by English Law.

Revolving Credit Facility On 11 September 2012, we entered in to a US$1,200 million five year committed revolving credit facility with a syndicate of 13 international banks. The Revolving Credit Facility is available for general corporate purposes.

The Revolving Credit Facility consists of two facilities; Facility A and Facility B (together, the “Facilities”). The Facility A Lenders (Barclays Bank PLC, Standard Chartered Bank, Abbey National Treasury Services PLC, Citibank N.A., London Branch, Crédit Agricole Corporate Investment Bank, Deutsche Bank Luxembourg S.A., the Royal Bank of Scotland PLC, HSBC Bank PLC, First Gulf Bank PJSC, JP Morgan Chase Bank N.A, London Branch, the Bank of Tokyo-Mitsubishi UFJ, Ltd, Arab Bank PLC, and HSBC Bank Middle East Limited) have made available a US dollar revolving loan to the RCF Borrowers (as defined below) with total commitments of an aggregate amount equal to US$1,150,000,000 and the Facility B Lenders (Mashreqbank PSC) have made available a Dirham revolving loan facility with total commitments of an aggregate amount equal to AED 183,650,000.

The borrowers under the Revolving Credit Facility are Petrofac Treasury B.V. and Petrofac International (UAE) LLC (together with any additional borrowers, the “RCF Borrowers”) and the other wholly owned subsidiaries of the Company may accede to the Revolving Credit Facility as additional borrowers. The Revolving Credit Facility is currently guaranteed by the Company, Petrofac International Ltd, Petrofac Treasury B.V. and Petrofac International (UAE) LLC (together with any additional guarantors, the “RCF Guarantors”, and together with the RCF Borrowers, the “Obligors”). The agent of the finance parties under the Revolving Credit Facility is Standard Chartered Bank (the “Agent”).

The Facilities can be applied by the RCF Borrowers towards the general corporate purposes of the Group. Facility A can be drawn by a Facility A borrower in a minimum amount of US$25,000,000 and in integral multiples of US$5,000,000. The amount drawn from Facility B must be in the same proportion to Facility B as

62 the amount drawn from Facility A is in proportion to Facility A, such that lenders from both Facility B and Facility A bear a pro-rata percentage of the total loan commitments. Utilisation requests under the Facilities can be submitted at any time falling three months prior to the termination date of the Revolving Credit Facility, which is 11 September 2017.

Repayments and Prepayments Each RCF Borrower that has drawn a loan under Facility A or Facility B is obliged to repay that loan on the last day of its interest period. The Revolving Credit Facility terminates on the fifth anniversary of the date of the Revolving Credit Facility and all outstanding amounts need to be repaid on this date. An RCF Borrower may select an interest period of three, six, nine or 12 months or any other period agreed between the Company and the Agent. Interest periods are selected when a utilisation request is submitted and cannot exceed the termination date of 11 September 2017.

Subject to certain conditions, the Facility A borrowers may voluntarily prepay any Facility A loan and/or cancel all or any part of the total Facility A commitments (provided partial cancellation or prepayment is for a minimum amount of US$25,000,000) by giving the Agent five business days notice of its intention to prepay or cancel such amounts provided that the borrower makes a simultaneous prepayment and/or cancellation pro rata to the whole or to any part of the corresponding Facility B Loan.

In addition to voluntary prepayments, the Revolving Credit Facility requires mandatory cancellation and, if applicable, prepayment in full or in part in certain circumstances, including: • Illegality—with respect to any lender, if it becomes unlawful for that lender to perform any of its obligations as contemplated under the Revolving Credit Facility or to fund or maintain its participation in any Facility A or Facility B loan.

On the occurrence of an “illegality” event, the commitment of the relevant lender will be immediately cancelled and the RCF Borrower shall be obliged to repay that lender’s participation in the loans made to that RCF Borrower on the last day of the interest period for each loan occurring after the Agent has notified the Company or, if earlier, a date specified by the lender in the notice delivered to the Agent; • Change of Control—if any person or group of persons acting in concert gains control of the Company. Under the terms of the Revolving Credit Facility, “control” is defined as meaning ownership (direct or indirect) of more than 50% of the issued voting capital of the Company. “Acting in concert” is defined as meaning any group of persons who pursuant to an agreement or understanding (whether formal or informal) actively co-operate either directly or indirectly.

On the occurrence of this event, a lender shall not be obliged to fund a utilisation and may instruct the Agent, with 15 business days’ notice to the Company, to cancel the commitment of that lender and declare that the participation of that lender in all outstanding loans is immediately due and payable.

Interest and Fees The Revolving Credit Facility will bear interest at a rate per annum equal to a margin of 1.5% per annum, plus certain mandatory costs and, in respect of Facility A, LIBOR and, in respect of Facility B, EIBOR. Certain other fees such as a commitment fee and a utilisation fee are also payable by the RCF Borrowers in connection with the Revolving Credit Facility.

Security and Guarantees The Revolving Credit Facility is an unsecured facility. The Revolving Credit Facility is guaranteed irrevocably and unconditionally by each of the original RCF Guarantors (as listed above) jointly and severally with each RCF Guarantor guaranteeing to each finance party under the Revolving Credit Facility the RCF Borrower’s punctual performance of its obligations under the Revolving Credit Facility. The guarantees are expressed to be continuing and extend to the ultimate balance of the sums payable by any Obligor under the Revolving Credit Facility. The Company is obliged to procure that, at certain test dates, the members of its Group that are RCF Guarantors represent, in aggregate, at least 70% or more of the consolidated EBITDA and the total assets of the Group.

Covenants The Revolving Credit Facility contains certain financial covenants which the Company must comply with during the term of the Revolving Credit Facility. The Company must comply with a leverage test to ensure that the ratio

63 of its consolidated net debt does not exceed 3:1 to consolidated EBITDA. The Company is also obliged to ensure that the ratio of its consolidated EBITDA to consolidated net finance expenses for the same period must be at least 3:1. Both of these financial covenants are tested when the Company submits its annual and half yearly consolidated financial statements to the Agent. Under the terms of the Revolving Credit Facility, these need to be submitted as soon as they are available and in any event, in the case of the unaudited consolidated financial statements for the relevant financial year, within 180 days after the end of that financial year and in the case of the unaudited consolidated half yearly financial statements within 90 days after the end of that half year.

The Revolving Credit Facility contains the customary information and negative covenants which are subject to certain agreed exceptions and materiality carve outs. The main restrictive covenants are as follows:

Negative Pledge The Revolving Credit Facility includes a negative pledge clause under which the Obligors undertake that they shall not nor shall they permit any other member of the Group to create or permit to subsist any security over any of its assets. This general restriction is subject to a series of carve outs and exceptions which include certain permitted existing security which the Company and its subsidiaries have already entered into or any security securing indebtedness as long as the principal amount of that indebtedness in the aggregate does not exceed US$150,000,000 (or its equivalent in another currency) (the “Negative Pledge Basket”).

Disposals The members of the Group have undertaken not to and to procure that no other member of the Group will enter into any transaction or series of transactions which involve the sale, lease or transfer of any asset of the Group. Again, this is subject to certain exceptions which include disposals made in the ordinary course of the business of the disposing entity, the disposal of obsolete or redundant assets which are no longer required by the Group, and disposals where the market value or consideration receivable for such disposal does not exceed an amount equal to 10% of the total assets of the Group in any financial year.

Acquisitions The members of the Group are prohibited from entering into a single transaction or a series of transactions to acquire assets or to make investments if the relevant transaction would be categorised under the UK Listing Rules as a “Class 1 Transaction”. This prohibition is subject to an exception where the relevant member of the Group proposing to make the acquisition has obtained the prior written consent of the Agent acting on the instruction of the Majority Lenders (as defined below).

Financial Indebtedness and Permitted Guarantees No member of the Group (other than the Obligors) may incur any financial indebtedness or permit any financial indebtedness to remain outstanding subject to certain carve outs and exceptions which include intra-group lending, financial indebtedness incurred with the prior written consent of the majority lenders (being the lender or lenders whose commitments aggregate to more than 66 2/3% of the total outstanding commitments under the Revolving Credit Facility) (the “Majority Lenders”) or any financial indebtedness which, when aggregated with any indebtedness that has the benefit of any security given under the Negative Pledge Basket, does not exceed US$150,000,000 (or its equivalent in another currency).

Subject to certain exceptions, none of the Obligors may incur or allow to remain outstanding any guarantee in respect of any obligation of any person. Following an amendment to the Revolving Credit Facility dated 17 April 2013, any Obligor is permitted to provide a guarantee in respect of indebtedness incurred by any other Obligor.

Events of Default The Revolving Credit Facility contains customary events of default (subject in certain cases to agreed grace periods, thresholds and other qualifications), including any breach of the financial covenants described above, a cross default with respect to any financial indebtedness of the Group that remains unpaid when it falls due. No cross default event of default will occur if the aggregate amount of any financial indebtedness that remains outstanding when it falls due does not exceed US$50,000,000.

Other events of default include a change in ownership of any Obligor where the relevant Obligor ceases to be a wholly owned subsidiary of the Company and the commencement of any litigation, arbitration or other

64 proceedings against any Obligor or other Group subsidiary which is deemed to be material under the Revolving Credit Facility if such litigation could be considered to have a reasonable prospect of success and such success would have a material adverse effect on the Group.

The occurrence of an event of default which is continuing will entitle the Agent, if so directed by the Majority Lenders, to (i) cancel all Facility A and Facility B commitments under the Revolving Credit Facility; (ii) declare all the loans made available to the RCF Borrowers to be immediately due and payable; and (iii) declare that all or part of the loans under the Revolving Credit Facility are repayable on demand.

Governing law The Revolving Credit Facility and any non-contractual obligations arising out of or in connection with it are governed by English law. The parties to the Revolving Credit Facility have agreed that any dispute arising between them in connection with the Revolving Credit Facility will be referred to and finally resolved via arbitration proceedings under the DIFC-LCIA Arbitration Centre and the seat of the arbitration shall be the Dubai International Financial Centre, Dubai, United Arab Emirates.

Capital Expenditure Historical Capital Expenditure For the six months ended 30 June 2013 and 30 June 2012, and in the years ended 31 December 2012, 2011 and 2010, we made capital expenditures of US$245 million, US$203 million, US$595 million, US$475 million and US$132 million, respectively. The following charts show the breakdown of capital expenditure by reporting segment for the periods indicated:

Six Months Ended 30 June 2013 2012(1) Property, Property, Plant and Intangible Plant and Intangible Equipment Oil & Gas Total Equipment Oil & Gas Total (unaudited) (US$ millions) Onshore Engineering & Construction ...... 38 — 38 34 — 34 Offshore Projects & Operations ...... 2 — 2 8 — 8 Engineering & Consulting Services ...... — — — 1 — 1 Integrated Energy Services ...... 160 44 204 105 54 159 Corporate & others ...... 1 — 1 1 — 1 Consolidation adjustments & eliminations ...... — — — — — — Total ...... 201 44 245 149 54 203

Year Ended 31 December 2012 2011 2010 Property, Intangible Property, Intangible Property, Intangible Plant and Oil & Gas Plant and Oil & Gas Plant and Oil & Gas Equipment Assets Total Equipment Assets Total Equipment Assets Total (audited) (US$ millions) Onshore Engineering & Construction ...... 76 — 76 54 — 54 60 — 60 Offshore Projects & Operations ...... 13 — 13 58 — 58 3 — 3 Engineering & Consulting Services ...... 7 — 7 8 — 8 3 — 3 Integrated Energy Services ..... 355 165 520 312 40 352 46 16 62 Corporate & others ...... 4 — 4 6 — 6 5 — 5 Consolidation adjustments & eliminations ...... (25) — (25) (3) — (3) (1) — (1) Total ...... 430 165 595 435 40 475 116 16 132

65 For details of the capital expenditure for the six months ended 30 June 2013 and 30 June 2012 and the years ended 31 December 2012 and 2011, see “—Cash Flows—Net Cash Flows Used in Investing Activities”. Capital expenditure in 2010 consisted mainly of investment in temporary project camps and vehicles in OEC and, in IES, development expenditure on the Don assets, upgrade work on the FPF1 floating production facility and the costs of near field appraisal wells in Block PM304, offshore Malaysia.

Current and Planned Capital Expenditures In addition to our historical capital expenditures, we expect a capital outlay of US$1 billion over the next five years in our offshore EPIC services capability including investment in a flagship high specification, multifunction vessel that will provide access to the deepwater and subsea markets.

We intend to continue investing in our service lines, particularly in the IES reporting segment and we anticipate gross investment in IES projects of between approximately US$500 million and US$1 billion per year over the next five years.

IES and OCP have significant funding requirements from their existing operations and growth strategies, and will be funded by a combination of other indebtedness, the net proceeds from the Offering and excess cash flows from operations.

Contractual Obligations and Contingent Liabilities The table below summarises our contractual commitments as of 30 June 2013:

Less More than 2to5 than 1 year years 5 years Total (unaudited) (US$ millions) Long-term borrowings and overdrafts ...... 73 798 37 908 Finance lease creditors ...... 5 4 — 9 Operating lease commitments ...... 60 229 188 477 Derivative instruments (crude oil swaps & forward currency contracts) ...... 6 1 — 7 Capital commitments ...... 259 264 47 570 Contingent consideration payable on acquisitions ...... 7 1 — 8 Total ...... 410 1,297 272 1,979

Contingencies In the normal course of business we obtain letters of credit and guarantees, which are contractually required to secure performance, advance payment or in lieu of retentions being withheld. Some of these facilities are guaranteed by the Company in favour of the issuing banks.

As of 30 June 2013, we had outstanding project performance guarantees of US$1,995 million, advance payment guarantees of US$657 million and retention guarantees of US$119 million.

Off-Balance Sheet Arrangements Other than as disclosed in “—Contractual Obligations and Contingent Liabilities”, as of 30 June 2013, the Company had no other off-balance sheet arrangements that could have a material adverse effect on our results of operations and financial position.

Critical Accounting Policies Our significant and critical accounting policies used in preparing the Financial Statements are set out below. Such policies involve a high degree of judgement and complexity and that, in turn, could materially impact our Financial Statements if various estimates and assumptions were changed significantly. More details of our accounting policies can be found in note 2 to the 2012 Consolidated Financial Statements.

66 Judgements In the process of applying our accounting policies, our Senior Management has made the following judgements, apart from those involving estimations, which have the most significant effect on the amounts recognised in the Financial Statements: • Revenue recognition on fixed-price EPC contracts: we recognise revenue on fixed-price EPC contracts using the percentage-of-completion method, based on surveys of work performed. We believe this basis of revenue recognition is the best available measure of progress on such contracts. • Revenue recognition on IES contracts: we assess on a case-by-case basis the most appropriate treatment for our various commercial structures which include RSCs, PECs and equity upstream investments, such as PSCs.

Estimation Uncertainty The key assumptions concerning the future and other key sources of estimation uncertainty at the statement of financial position date that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below: • Project cost to completion estimates: at each statement of financial position date we are required to estimate costs to completion on fixed-price contracts. Estimating costs to complete on such contracts requires us to make estimates of future costs to be incurred, based on work to be performed beyond the statement of financial position date. This estimate will impact revenue, cost of sales, work-in-progress, billings in excess of costs and estimated earnings and accrued contract expenses. • Onerous contract provisions: we provide for future losses on long-term contracts where it is considered probable that the contract costs are likely to exceed revenue in future years. Estimating such future losses involves a number of assumptions about the achievement of contract performance targets and the likely levels of future cost escalation over time. • Impairment of goodwill: we determine whether goodwill is impaired at least on an annual basis. This requires an estimation of the value in use of the cash-generating units to which the goodwill is allocated. Estimating the value in use requires us to make an estimate of the expected future cash flows from each cash-generating unit and also to determine a suitable discount rate in order to calculate the present value of such cash flows. • Deferred tax assets: we recognise deferred tax assets on all applicable temporary differences where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the amount of deferred tax that can be recognised based on the magnitude and likelihood of future taxable profits. • Income tax: the Company and its subsidiaries are subject to routine tax audits and also a process whereby tax computations are discussed and agreed with the appropriate authorities. Whilst the ultimate outcome of such tax audits and discussions cannot be determined with certainty, management estimates the level of provisions required for both current and deferred tax on the basis of professional advice and the nature of current discussions with the tax authority concerned. • Recoverable value of intangible oil and gas and other intangible assets: the Group determines at each statement of financial position date whether there is any evidence of indicators of impairment in the carrying value of its intangible oil and gas and other intangible assets. Where indicators exist, an impairment test is undertaken which requires Senior Management to estimate the recoverable value of its intangible assets for example by reference to quoted market values, similar arm’s length transactions involving these assets or value in use calculations. • Units of production depreciation: estimated proven plus probable reserves are used in determining the depreciation of oil and gas assets such that the depreciation charge is proportional to the depletion of the remaining reserves over their life of production. These calculations require the use of estimates including the amount of economically recoverable reserves and future oil and gas capital expenditure.

67 Revenue Recognition Revenue is recognised to the extent that it is probable economic benefits will flow to us and the revenue can be reliably measured. The following specific recognition criteria also apply:

Onshore Engineering & Construction Revenue from fixed-price lump-sum contracts is recognised on the percentage-of-completion method, based on surveys of work performed once the outcome of a contract can be estimated reliably. In the early stages of contract completion, when the outcome of a contract cannot be estimated reliably, contract revenue is recognised only to the extent of costs incurred that are expected to be recoverable.

Revenue from cost-plus-fee contracts is recognised on the basis of costs incurred during the year plus the fee earned measured by the cost-to-cost method, where rather than using a measured physical percentage of completion method, we use the cost incurred to date divided by expected total costs of the project to completion.

Revenue from reimbursable contracts is recognised in the period in which the services are provided based on the agreed contract schedule of compensation rates.

Provision is made for all losses expected to arise on completion of contracts entered into at the statement of financial position date, whether or not work has commenced on such contracts.

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded and the amount of the incentive payments can be measured reliably. Variation orders, which arise from additional work done on the project outside the initial scope of the contract where the customer issues a new purchase order for those changes, are only included in revenue when it is probable they will be accepted and can be measured reliably and claims are only included in revenue when negotiations have reached an advanced stage.

Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services Revenue from reimbursable contracts is recognised in the period in which the services are provided based on the agreed contract schedule of compensation rates.

Revenue from fixed-price contracts is recognised on the percentage-of-completion method, measured by milestones completed or earned value once the outcome of a contract can be estimated reliably. In the early stages of contract completion, when the outcome of a contract cannot be estimated reliably, contract revenue is recognised only to the extent of costs incurred that are expected to be recoverable.

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded and the amount of the incentive payments can be measured reliably. Claims on incentive payments 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.

Integrated Energy Services Oil and gas revenue comprises our share of sales from the processing or sale of hydrocarbons from our equity upstream investments such as PSCs on an entitlement basis, when the significant risks and rewards of ownership have been passed on to the buyer.

Revenue from PECs is recognised based on the volume of hydrocarbons produced in the period and the agreed tariff and the reimbursement arrangement for costs incurred.

Revenue recognition for RSCs varies from contract to contract, as the structure of each RSC is dependent on the needs of the particular client.

Goodwill Goodwill acquired in a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that such carrying value may be impaired. All transaction costs associated with business combinations are charged to the consolidated income statement in the year of such combination.

68 For the purpose of impairment testing, goodwill acquired is allocated to the cash-generating units that are expected to benefit from the synergies of the combination. Each unit or units to which goodwill is allocated represents the lowest level within the Group at which the goodwill is monitored for internal management purposes and is not larger than an operating segment determined in accordance with IFRS 8 “Operating Segments”.

Impairment is determined by assessing the recoverable amount of the cash-generating units to which the goodwill relates. Where the recoverable amount of the cash-generating units is less than the carrying amount of the cash-generating units and related goodwill, an impairment loss is recognised.

Where goodwill has been allocated to cash-generating units and part of the operation within such units is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed of in this circumstance is measured based on the relative values of the disposed operation and the portion of the cash- generating units retained.

Intangible Assets—Non Oil and Gas Assets Intangible assets acquired in a business combination are initially measured at cost, being their fair values at the date of acquisition and are recognised separately from goodwill where the asset is separable or arises from a contractual or other legal right and its fair value can be measured reliably. After initial recognition, intangible assets are carried at cost less accumulated amortisation and any accumulated impairment losses. Intangible assets with a finite life are amortised over their useful economic life using a straight-line method unless a better method reflecting the pattern in which the asset’s future economic benefits are expected to be consumed can be determined. The amortisation charge in respect of intangible assets is included in the selling, general and administration expenses line of the consolidated income statement. The expected useful lives of assets are reviewed on an annual basis. Any change in the useful life or pattern of consumption of the intangible asset is treated as a change in accounting estimate and is accounted for prospectively by changing the amortisation period or method. Intangible assets are tested for impairment whenever there is an indication that the asset may be impaired.

Oil and Gas Assets Capitalised Costs Our activities in relation to oil and gas assets are limited to assets in the evaluation, development and production phases.

Oil and gas evaluation and development expenditure is accounted for using the successful efforts method of accounting.

Evaluation Expenditures Expenditure directly associated with evaluation (or appraisal) activities is capitalised as an intangible asset. Such costs include the costs of acquiring an interest, appraisal well drilling costs, payments to contractors and an appropriate share of directly attributable overheads incurred during the evaluation phase. For such appraisal activity, which may require drilling of further wells, costs continue to be carried as an asset whilst related hydrocarbons are considered capable of commercial development. Such costs are subject to technical, commercial and management review to confirm the continued intent to develop, or otherwise extract value. When this is no longer the case, the costs are written-off in the income statement. When such assets are declared part of a commercial development, related costs are transferred to tangible oil and gas assets. All intangible oil and gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the consolidated income statement.

Development Expenditures Expenditure relating to development of assets which include the construction, installation and completion of infrastructure facilities such as platforms, pipelines and development wells, is capitalised within property, plant and equipment.

Changes in Unit-of-Production Factors Changes in factors which affect unit-of-production calculations are dealt with prospectively in accordance with the treatment of changes in accounting estimates, not by immediate adjustment of prior years’ amounts.

69 Decommissioning Provision for future decommissioning costs is made in full when we have an obligation to dismantle and remove a facility or a piece of equipment and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. The amount recognised is the present value of the estimated future expenditure. An amount equivalent to the discounted initial provision for decommissioning costs is capitalised and amortised over the life of the underlying asset on a unit-of-production basis over proven and probable reserves. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the oil and gas asset.

The unwinding of the discount applied to future decommissioning provisions is included under finance costs in the consolidated income statement.

Impairment of Assets (Excluding Goodwill) At each statement of financial position date, we review the carrying amounts of our tangible and intangible assets to assess whether there is an indication that those assets may be impaired. If any such indication exists, we make an estimate of the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows attributable to the asset are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.

If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. An impairment loss is recognised immediately in the consolidated income statement, unless the relevant asset is carried at a revalued amount, in which case the impairment loss is treated as a revaluation decrease.

Where an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior years. A reversal of an impairment loss is recognised immediately in the consolidated income statement, unless the relevant asset is carried at a revalued amount, in which case the reversal of the impairment is treated as a revaluation increase.

Work in progress and billings in excess of cost and estimated earnings Fixed price lump-sum EPC contracts are presented in the statement of financial position as follows: • For each contract, the accumulated cost incurred, as well as the estimated earnings recognised at the contract’s percentage of completion less provision for any anticipated losses, after deducting the progress payments received or receivable from the customers, are shown in current assets in the statement of financial position under “work in progress”. • Where the payments received or receivable for any contract exceed the cost and estimated earnings less provision for any anticipated losses, the excess is shown as “billings in excess of cost and estimated earnings” within current liabilities.

Income Taxes Income tax expense represents the sum of current income tax and deferred tax. Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid to taxation authorities. Taxable profit differs from profit as reported in the consolidated income statement because taxable profit excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. Our liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the statement of financial position date.

Deferred income tax is recognised on all temporary differences at the statement of financial position date between the carrying amounts of assets and liabilities in the Financial Statements and the corresponding tax bases used in the computation of taxable profit, with the following exceptions: • Where the temporary difference arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination that at the time of the transaction affects neither accounting nor taxable profit nor loss.

70 • In respect of taxable temporary differences associated with investments in subsidiaries, associates and joint ventures, where the timing of reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future. • Deferred income tax assets are recognised only to the extent that it is probable that a taxable profit will be available against which the deductible temporary differences, carried forward tax credits or tax losses can be utilised.

The carrying amount of deferred income tax assets is reviewed at each statement of financial position date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax assets to be utilised. Unrecognised deferred income tax assets are reassessed at each statement of financial position date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered.

Deferred income tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply when the asset is realised or the liability is settled, based on tax rates and tax laws enacted or substantively enacted at the statement of financial position date.

Current and deferred income tax is charged or credited directly to other comprehensive income or equity if it relates to items that are credited or charged to respectively, other comprehensive income or equity. Otherwise, income tax is recognised in the consolidated income statement.

Share-based Payments Our employees, including our Directors, receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares (“equity-settled transactions”).

Equity-settled transactions The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which the rights are granted. In valuing equity-settled transactions, service or performance conditions are not taken into account, other than conditions linked to the price of the shares of the Company in accordance with IFRS 2, if applicable.

The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the relevant employees become fully entitled to the award (the “vesting period”). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and our best estimate of the number of equity instruments that will ultimately vest. The income statement charge or credit for a period represents the movement in cumulative expense recognised as of the beginning and end of that period.

No expense is recognised for equity awards that do not ultimately vest, except for equity awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions and service conditions are satisfied. Equity awards that are cancelled are treated as vesting immediately on the date of cancellation, and any expense not recognised for the award at that date is recognised in the consolidated income statement.

Quantitative and Qualitative Disclosure about Market Risk Our Board Risk Committee approves and monitors the risk management processes of the Group, including documented treasury policies, counterparty limits and controlling and reporting structures.

Our principal financial assets and liabilities, other than derivatives, comprise available-for-sale financial assets, trade and other receivables, amounts due from/to related parties, cash and short-term deposits, work-in-progress, interest-bearing loans and borrowings, trade and other payables and contingent consideration. Our activities expose us to various financial risks particularly associated with interest rate risk on our variable rate cash and short-term deposits, loans and borrowings and foreign currency risk on both conducting business in currencies other than our reporting currency, as well as translation of the assets and liabilities of foreign operations into our reporting currency. We also have exposure to commodity price risk on our revenue and profits generated from sales of crude oil and gas. These risks are managed from time to time by using a combination of various derivative instruments, principally forward currency contracts in line with our hedging policies. We have a policy not to enter into speculative trading of financial derivatives.

71 The other main risks besides interest rate, foreign currency risk and commodity price risk arising from our financial instruments are credit risk and liquidity risk and the policies relating to these risks are discussed in detail below.

Interest Rate Risk Interest rate risk arises from the possibility that changes in interest rates will affect the value of our interest- bearing financial liabilities and assets.

Our exposure to market risk arising from changes in interest rates relates primarily to our variable rate debt obligations and cash and bank balances. Our policy is to manage our interest cost using a mix of fixed and variable rate debt. Our cash and bank balances are at floating rates of interest.

Interest rate sensitivity analysis The impact on our pre-tax profit and equity due to a reasonably possible change in interest rates on loans and borrowings at the reporting date is demonstrated in the table below. The analysis assumes that all other variables remain constant. Pre-tax profit Equity 100 basis 100 basis 100 basis 100 basis point point point point increase decrease increase decrease (audited) (US$ millions) 31 December 2012 ...... (2) 2 — — 31 December 2011 ...... (1) 1 — —

The following table reflects the maturity profile of these financial liabilities and assets: Year Ended 31 December 2012 More Within 1-2 2-3 3-4 4-5 than 1 year years years years years 5 years Total (audited) (US$ millions) Financial liabilities Floating rates Bank overdrafts ...... 57 ———— — 57 Revolving Credit Facility ...... — — — — 303 — 303 57 — — — 303 — 360 Financial assets Floating rates Cash and short-term deposits ...... 614 ———— — 614 Restricted cash balance ...... 4 7 — — — — 11 618 7 — — — — 625

Year Ended 31 December 2011 More Within 1-2 2-3 3-4 4-5 than 1 year years years years years 5 years Total (audited) (US$ millions) Financial liabilities Floating rates Bank overdrafts ...... 37 ———— — 37 Term loans ...... 24 19 — — — — 43 61 19 — — — — 80 Financial assets Floating rates Cash and short-term deposits ...... 1,572 ———— — 1,572 Restricted cash balance ...... 2 ———— — 2 1,574 ———— — 1,574

72 Financial liabilities in the above table are disclosed gross of debt acquisition costs and effective interest rate adjustments of US$11 million (2011: US$3 million).

Interest on financial instruments classified as floating rate is re-priced at intervals of less than one year. Our other financial instruments that are not included in the above tables are non-interest bearing and are therefore not subject to interest rate risk.

Foreign Currency Risk We are exposed to foreign currency risk on sales, purchases, and translation of assets and liabilities that are in a currency other than the functional currency of our operating units. We are also exposed to the translation of the functional currencies of our operating units to the US dollar reporting currency.

The following table summarises the percentage of foreign currency denominated revenue, costs, financial assets and financial liabilities, expressed in US dollar terms, of our totals.

2012 % of 2011 % of foreign foreign currency currency denominated denominated items items Revenue ...... 34.5% 36.4% Costs ...... 54.7% 57.7% Current financial assets ...... 37.8% 32.5% Non-current financial assets ...... 0.0% 0.0% Current financial liabilities ...... 33.9% 34.7% Non-current financial liabilities ...... 2.7% 54.2%

The significant decrease in the percentage of foreign currency denominated non-current financial liability items in 2012 was because as of 31 December 2011, our two term loans had both a sterling and US dollar component, whereas at 31 December 2012 we had US$303 million entirely in US dollars and no sterling debt other than an overdraft. We use forward currency contracts to manage the currency exposure on transactions significant to our operations. It is our policy not to enter into forward contracts until a highly probable forecast transaction is in place so that we are able to negotiate the terms of derivative instruments used for hedging that match the terms of the hedged item to maximise hedging effectiveness.

Foreign currency sensitivity analysis The income statements of our foreign operations are translated into our reporting currency using a weighted average exchange rate of conversion. Foreign currency monetary items are translated using the closing rate at the reporting date. Revenue and costs in currencies other than the functional currency of an operating unit are recorded at the prevailing rate at the date of the transaction. The following significant exchange rates applied during the year in relation to US dollars:

2012 2011 Average Closing Average Closing rate rate rate rate Sterling ...... 1.59 1.63 1.60 1.55 Kuwaiti dinar ...... 3.57 3.55 3.62 3.59 Euro ...... 1.29 1.32 1.40 1.30

The following table summarises the impact on our pre-tax profit and equity (due to change in the fair value of monetary assets, liabilities and derivative instruments) of a reasonably possible change in US dollar exchange rates with respect to different currencies:

Equity +10% US -10% US +10% US -10% US dollar rate dollar rate dollar rate dollar rate Pre-tax profit increase decrease increase decrease (audited) (US$ millions) 31 December 2012 ...... (10) 10 19 (19) 31 December 2011 ...... (4) 4 50 (50)

73 Derivative instruments designated as cash flow hedges At 31 December 2012, we had foreign exchange forward contracts as follows: Contract Fair value Fair value Net unrealised value (undesignated) (designated) gain/(loss) 2012 2011 2012 2011 2012 2011 2012 2011 (audited) (US$ millions) Euro purchases ...... 67 223 — — — (10) — (8) Sterling (sales) purchases ...... (103) 40 (2) — — (2) — (1) Yen (sales) ...... (4) (4) — — ———— Singapore dollar purchases ...... — 46 — — — (1) — (1) (2) — — (13) — (10)

The above foreign exchange contracts mature and will affect income between January 2013 and July 2014 (2011: between January 2012 and July 2013).

At 31 December 2012, we had cash and short-term deposits designated as cash flow hedges with net unrealised gains/(losses) of US$ nil (2011: US$9 million loss) as follows: Net unrealised Fair value gain/(loss) 2012 2011 2012 2011 (audited) (US$ millions) Euro cash and short-term deposits ...... 118 181 — (9) Sterling cash and short-term deposits ...... 7 15 — — Yen cash and short-term deposits ...... 1 3 — — — — — (9)

During 2012, changes in fair value gains of US$2 million (2011: US$14 million loss) relating to these derivative instruments and financial assets were taken to equity and US$18 million of losses (2011: US$3 million gains) were recycled from equity into cost of sales in the income statement. The forward points and ineffective portions of the above foreign exchange forward contracts and loss on un-designated derivatives of US$2 million (2011: US$6 million loss) were recognised in the income statement.

Commodity Price Risk—Oil Prices We are exposed to the impact of changes in oil and gas prices on our revenue and profits generated from sales of crude oil and gas. Our policy is to manage our exposure to the impact of changes in oil and gas prices using derivative instruments, primarily swaps and collars. Hedging is only undertaken once sufficiently reliable and regular long-term forecast production data is available.

During 2012, we entered into various crude oil swaps and zero cost collars hedging oil production of 1,000,000 barrels (“bbl”) (2011: 163,766 bbl) with maturities ranging from January 2013 to December 2013. In addition, fuel oil swaps were also entered into for hedging gas production of 31,743 metric tons (2011: 21,100 metric tons) with maturities from January 2013 to September 2013.

The fair value of oil derivatives at 31 December 2012 was US$ nil (2011: US$1 million liability) with net unrealised losses deferred in equity of US$ nil (2011 US$ nil). During 2012, losses of US$2 million (2011: US$ nil loss) were recycled from equity into the consolidated income statement on the occurrence of the hedged transactions and a loss in the fair value recognised in equity of US$2 million (2011: US$ nil).

The following table summarises the impact on our pre-tax profit and equity (due to a change in the fair value of oil derivative instruments and the underlifting asset/overlifting liability) of a reasonably possible change in the oil price Pre-tax profit Equity +10 -10 +10 -10 US$/bbl US$/bbl US$/bbl US$/bbl increase decrease increase decrease (audited) (US$ millions) 31 December 2012 ...... — — (12) 12 31 December 2011 ...... (1) 1 (2) 2

74 Credit risk We trade only with recognised, creditworthy third parties. Business Unit Risk Review Committees (“BURRC”) have been set up to evaluate the creditworthiness of each individual third-party at the time of entering into new contracts. Limits have been placed on the approval authority of the BURRC. Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary. At 31 December 2012, our five largest customers accounted for 48.8% of outstanding trade receivables and work in progress compared with 47.1% in 2011.

With respect to credit risk arising from our other financial assets, which comprise cash and cash equivalents, available-for-sale financial assets and certain derivative instruments, our exposure to credit risk arises from default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments. We limit credit risk on liquid funds and derivative instruments through diversification of exposures with a range of approved financial institutions. Counterparty limits are set for each financial institution with reference to credit ratings assigned by S&P and Moody’s.

Liquidity risk Our primary objective is to ensure sufficient liquidity to support future growth. Our IES strategy includes the provision of financial capital and the potential impact on our capital structure is reviewed regularly.

The maturity profiles of our financial liabilities at 31 December 2012 are as follows:

Year Ended 31 December 2012 More Contractual 6 months 6-12 1-2 2-5 than undiscounted Carrying or less months years years 5 years cash flow amount (audited) (US$ millions) Financial liabilities Interest-bearing loans and borrowings ...... 57 — — 303 — 360 349 Finance lease creditors ...... — 8 6 — — 14 13 Trade and other payables (excluding advances from customers) ...... 1,464 104 — — — 1,568 1,568 Due to related parties ...... 38 — — — — 38 38 Contingent consideration ...... 1 6 2 — — 9 8 Derivative instruments ...... 3 — 1 — — 4 4 Interest payments ...... 4 3 6 6 — 19 — 1,567 121 15 309 — 2,012 1,980

The maturity profiles of our financial liabilities at 31 December 2011 are as follows:

Year Ended 31 December 2011 More Contractual 6 months 6-12 1-2 2-5 than undiscounted Carrying or less months years years 5 years cash flow amount (audited) (US$ millions) Financial liabilities Interest-bearing loans and borrowings ...... 48 12 20 — — 80 77 Finance lease creditors ...... — 6 11 — — 17 16 Trade and other payables (excluding advances from customers) ...... 932 16 — — — 948 948 Due to related parties ...... 23 — — — — 23 23 Contingent consideration ...... 2 2 13 — — 17 16 Derivative instruments ...... 20 3 — — — 23 23 1,025 39 44 — — 1,108 1,103

We use various funded facilities provided by banks and our own financial assets to fund the above mentioned financial liabilities.

75 BUSINESS

The following table sets forth our revenue, EBITDA, operating profit and profit attributable to Petrofac Limited shareholders for the periods indicated:

76 For the six months ended 30 June 2013, the ECOM division accounted for 85% of our revenue, 69% of our EBITDA, 79% of our operating profit and 81% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, the ECOM division accounted for 89% of our revenue, 78% of our EBITDA, 83% of our operating profit and 86% of our profit attributable to Petrofac Limited shareholders. ECOM operations are split into three distinct reporting segments which are focused predominately on markets in the Middle East, the UKCS, Africa and the CIS: • OEC delivers onshore EPC projects. For the six months ended 30 June 2013, OEC accounted for 56% of our revenue, 59% of our EBITDA, 70% of our operating profit and 74% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, OEC accounted for 64% of our revenue, 64% of our EBITDA, 69% of our operating profit and 73% of our profit attributable to Petrofac Limited shareholders. • OPO specialises in onshore and offshore operations and maintenance and brownfield modification projects and, through the OCP service line, specialises in providing offshore EPIC services for greenfield projects. For the six months ended 30 June 2013, OPO accounted for 23% of our revenue, 8% of our EBITDA, 7% of our operating profit and 5% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, OPO accounted for 21% of our revenue, 10% of our EBITDA, 10% of our operating profit and 9% of our profit attributable to Petrofac Limited shareholders. • ECS delivers early-stage engineering studies, including conceptual and FEED work across onshore and offshore oil and gas fields. For the six months ended 30 June 2013, ECS accounted for 6% of our revenue, 2% of our EBITDA, 2% of our operating profit and 3% of our profit attributable to Petrofac Limited shareholders. For the year ended 31 December 2012, ECS accounted for 4% of our revenue, 4% of our EBITDA, 4% of our operating profit and 4% of profit attributable to Petrofac Limited shareholders.

Heritage The following is a timeline describing significant milestones in our history:

1981 Petrofac was established as a producer of modular plant in Tyler, Texas, USA with 25 members of staff. 1991 Ayman Asfari and Maroun Semaan joined the team and established Petrofac International Ltd as an EPC business, with an operational centre in Sharjah, United Arab Emirates. 1997 The Resources (now Developments) business was created, combining our capabilities in design, construction and operation of facilities and infrastructure with a commercial approach to investment. 2000 We were awarded the landmark 39-month Ohanet project in Algeria, a joint venture with ABB Lummus, at the time a subsidiary of ABB Ltd., valued at US$600 million. This project was our first RSC. 2001 Our engineering and construction services were expanded to include field facilities and development planning, early stage engineering, design and consultancy. We established a new office in Woking, England. 2002 We acquired PGS Production to create a facilities management business in Aberdeen, Scotland.

77 2003 Our US Engineering, Procurement and Fabrication business was sold. 2004 We acquired RGIT Montrose and Rubicon Response, leading to the creation of Petrofac Training Services and expanding our service offering to include competence and technical training and emergency response capability. 2005 We were admitted to the Official List of the London Stock Exchange with a market capitalisation of around US$1.3 billion. 2008 We entered the FTSE 100. 2010 We completed the demerger of our UKCS Don field assets to form EnQuest PLC. 2011 As part of a wider reorganisation, we created the IES division to help deliver the next stage of our strategic development. 2012 We formally established a new service line, OCP, to focus on taking EPC capability offshore and to deliver EPIC projects.

Competitive Strengths We believe that the following are our key strengths:

Business Line Diversification through Innovative Business Models We have developed a geographically diverse portfolio and seek to continue our move away from our concentration in a limited number of regions, thereby enhancing our business profile. Furthermore, we have diversified our contractual offerings through our IES division, which provides integrated service contracts of a longer duration than the typical EPC contract, in particular through our expansion into RSCs and PECs, the latter of which can last up to 25 years or longer.

According to the IEA, NOCs share of global oil production is expected to increase over the next decade, driven by an increased desire by countries to maintain sovereignty over their hydrocarbon resources and increased technical capabilities and operating experience within NOCs meaning they no longer need to rely on IOCs to the same extent. Our greenfield development offering through the use of RSCs and our brownfield production enhancement offering through the use of PECs do not require the resource holder to hand over ownership of reserves, making it appealing to NOCs who may be reluctant to do so. By delivering projects on a service basis, with contract terms that incentivise us to deliver the project on time and within budget or to continue to increase

78 the production of a field, we are aligned with the interests of the resource holder. This alignment can be cemented further through our ability to invest in the projects and, through Training Services, to train and develop the workforce to build, maintain and operate the infrastructure going forward. As such, by working with us, NOCs are able to access our extensive engineering, project management, delivery and operating experience to develop or improve recovery from resources which they otherwise might not have been able to, while at the same time retaining full ownership of the underlying reserves and developing the local economy and workforce in the process.

Strong Long-term Relationships Throughout our development, we have sought to create and maintain a number of strong long-term relationships with strategic customers and partners, often through our Directors, Senior Management and other employees over the course of their careers with us. These relationships include NOCs such as ADCO, KOC, Pemex, Petronas, Saudi Aramco; IOCs such as BP, Shell and Total; and other strategic partners including Schlumberger and SapuraKencana. Our long-term relationships with customers have allowed us to gain a strong understanding of their needs and to become a trusted partner for their customised solutions.

Strong EBITDA Performance Historically, we have had strong cash flow generating capability, with a net cash position throughout 2012, 2011 and 2010. Whilst the ECOM division can show significant volatility in working capital, reflecting the phasing of EPC contract advances and other EPC receipts and payments, over time the division generates significant operating cash inflow from its portfolio of EPC and other contracts. For the six months ended 30 June 2013, ECOM EBITDA was US$262 million and for 2012, 2011 and 2010, ECOM EBITDA was US$711 million, US$687 million and US$525 million, respectively. For the six months ended 30 June 2013, IES EBITDA was US$116 million and for the years ended 31 December 2012, 2011 and 2010, IES EBITDA was US$196 million, US$89 million and US$127 million, respectively. Through IES, we invest in RSCs, PSCs and PECs in countries such as Malaysia, Mexico, Romania and the United Kingdom. Our increased investments in IES caused our net cash (including unamortised debt acquisition costs) to decrease from US$1,495 million at the end of 2011 to US$265 million at the end of 2012. As of 30 June 2013, we had net debt (including unamortised debt acquisition costs) of US$370 million, with the cash outflow over the first six months of the year being predominately due to movements in working capital of US$485 million in our OEC and IES businesses (the result in part of timing differences on OEC lump-sum contracts in the first half of 2013 compared with the first half of 2012), and capital expenditure of US$201 million mainly in relation to IES projects. We expect to remain in a net debt position in the medium term, driven by the ongoing deployment of cash on IES projects and initial investment in our offshore strategy. However, as our IES portfolio of assets and EPIC strategy mature beyond the initial project investment phase, they are also expected to become increasingly cash generative.

79 and gas industry and has held management positions either at our Group or at other leading oil and gas companies such as AMEC, BP, ConocoPhillips and Halliburton. Our market leading position, successful operating performance, financial performance, track record and strong relationships are all evidence of the strength of our Directors and Senior Management.

Delivering Geographical Expansion From our inception in the United States in 1981, we have grown to become an international business with operations in 29 countries, and we intend to continue our policy of careful geographic expansion. We believe that this will help us to create fresh opportunities and make us more resilient to challenges in individual regions of the world, ensuring that our portfolio remains balanced and robust. We implement this strategy through selecting those geographies that have substantial hydrocarbon reserves and which will allow us to transact business safely and responsibly. We focus in particular on those regions where we believe our mix of innovative contract options, preference for delivering services with local partners and ability to train and develop local workforces make us particularly effective and differentiate us from our competitors. This approach allowed us to become one of the first foreign companies in more than 70 years to operate a Mexican oilfield, when the state-owned Pemex awarded us a 25-year integrated production service contract for the Magallanes and Santuario blocks in Tabasco State in August 2011. Furthermore in 2012 we built on our presence in West Africa and Saudi Arabia. In November 2012, we signed a strategic alliance with Bowleven, an Africa-focused gas company, for a proposed development of the Etinde Permit in offshore Cameroon. In July 2012, in Saudi Arabia, we won two EPC contracts for Phase II of the petrochemical expansion project for Petro Rabigh, and in December 2012 Saudi Aramco awarded us two further EPC contracts for the Jazan refinery and terminal project. We intend to continue to grow our activities in recently-entered countries and move into new markets in the CIS, East Africa and South East Asia.

Offshore oil and gas production is expected to play an increasing role in the oil and gas sector, especially deeper water production, with the offshore market expected to require capital expenditure of US$100 billion in 2013 forecasted to grow to US$150 billion by 2020, according to Douglas-Westwood. The deeper water activities (SURF and pipelines) are expected to provide the strongest growth potential in this time period of over 15% per year in terms of capital expenditure, while competition has consolidated within this high-end offshore segment with just three main EPIC providers, Saipem, Technip and Subsea 7. To address this opportunity and expand our OCP offering, we are implementing a plan to build a high quality OCP team which can deliver offshore projects in both shallow and deep waters. In February 2013, we announced our intention to invest up to US$1 billion over the next five years in building our own installation capability, underpinned by one high specification, multi-function derrick lay vessel. Our aspiration through this investment in both assets and people is to become a top-tier offshore EPIC service provider, thus leveraging our considerable offshore operational experience, project management and engineering skills and further diversifying our geographic and service offering portfolio.

80 wish to retain control of their own reserves and to develop local capabilities and supply chains, our flexible model positions us to capitalise on the NOCs’ growing share of global oil production. IES projects cover upstream developments, both greenfield and brownfield, and related energy infrastructure projects, which often include investments of our capital, such as investment in and deployment of floating production units. Our global portfolio of projects includes the Arenque, Magallanes, Pánuco and Santuario PECs with Pemex, the offshore Berantai project in Malaysia, the Ticleni oilfield in Romania and in the Greater Stella Area in the North Sea, where we will have a 20% production share when we achieve first oil. We intend to continue to broaden this portfolio through developing the capabilities that allow us to meet customer needs, and will continue to consider options such as investment in energy infrastructure projects. Increased upstream activity has required that we expand in areas such as specialist subsurface engineering, drilling and asset management; as a result, we have established a technical centre in our UK office in Woking, and we are setting up another technical centre in Delhi, India. Furthermore, NOCs often require that we use and develop local staff, and so we are continuing to expand our technical skills training capability offered by Training Services which we can deploy to develop local workforces and increase competence.

Description of the Business Organisational Structure The following shows the relationship of the Company and the Guarantors, including the Company’s effective direct and indirect holdings in the Guarantors:

Petrofac Limited

Petrofac International Ltd Other non-guarantor 100% subsidiaries

Petrofac International (UAE) LLC 100%

For a complete list of our subsidiaries as of 31 December 2012, see note 32 (Principal Subsidiaries and Joint Ventures) to our audited financial statements for the year ended 31 December 2012, beginning on page F-77 of this Offering Memorandum.

81 Operational Structure Our operations are conducted through our ECOM and IES divisions, within which we operate seven service lines under four reporting segments. The ECOM division is organised into three reporting segments and four service lines, while the IES division is organised as a single reporting segment organised into three service lines. The following table illustrates the structure of our ECOM and IES divisions:

Divisions Engineering, Construction, Operations & Maintenance Integrated Energy Services

Reporting Onshore Engineering & Segments Engineering & Offshore Projects & Operations Consulting Integrated Energy Services Construction Services

Onshore Offshore Offshore Engineering & Service Training Production Engineering & Projects & Capital Consulting Developments Lines Services solutions Construction Operations Projects Services

We provide these services on a standalone or integrated basis and through a range of different commercial models tailored to meet our customers’ needs.

Engineering, Construction, Operations & Maintenance Our ECOM division designs and builds oil and gas facilities and operates, manages and maintains them on behalf of its customers. Its service offerings include FEED, detailed design engineering, project and construction management, procurement engineering, commissioning, operations and maintenance. Our ECOM capabilities extend to both onshore and offshore and greenfield and brownfield projects. In providing these services, we rely on contractors, vendors and sub-contractors, particularly in the construction phase of our major EPC contracts. For the six months ended 30 June 2013, ECOM accounted for 85% of our revenue, 69% of our EBITDA, 79% of our operating profit and 81% of our profit attributable to Petrofac Limited shareholders. In 2012, the ECOM division accounted for 89% of our revenue, 78% of our EBITDA, 83% of our operating profit and 86% of our profit attributable to Petrofac Limited shareholders. ECOM reports in three segments: OEC, OPO and ECS.

Onshore Engineering & Construction OEC is a single service line that delivers onshore EPC oil and gas projects. Our services on these projects cover concept and FEED design, detailed design, project and construction management, procurement, transportation fabrication, construction, pre-commissioning, commissioning and start-up. Core areas of expertise include: • oil and gas gathering and production facilities; • crude separation and stabilisation; • gas processing and compression; • high pressure water and gas re-injection; • sulphur recovery; • oil terminals and pumping stations; • flowlines and pipeline systems; and • liquefied petroleum gas and natural gas liquids (“NGL”) recovery, including turbo-expander plants.

OEC’s operations are currently focused on markets in the Middle East, Africa and the Caspian region of the CIS. As of 30 June 2013, OEC had 6,565 employees.

The majority of our EPC contracts are undertaken on a lump-sum or fixed-price basis, meaning that EPC revenues consist of an all-inclusive lump-sum price for the completed project. Depending on the terms of the

82 EPC contract, payment is usually received by reference to the achievement of milestones over the life of the contract and in some cases we may receive advance payments. EPC contracts typically have a duration of two to four years. OEC will not bid, or will discontinue a bid, where we believe that an appropriate margin is not feasible.

For the six months ended 30 June 2013, OEC accounted for 56% of our revenue, 59% of our EBITDA, 70% of our operating profit and 74% of our profit attributable to Petrofac Limited shareholders. In 2012, OEC accounted for 64% of our revenue, 64% of our EBITDA, 69% of our operating profit and 73% of our profit attributable to Petrofac Limited shareholders.

The following table sets out OEC’s current key projects.

Value(1) Year Completion Project Location Customer (US$ millions) Awarded Date Asab onshore oil field development ...... AbuDhabi NOC 2,300 2009 2013 El Merk gas processing facility ...... Algeria NOC/IOC 2,200 2009 2013 GASCO 4th NGL train(2) ...... AbuDhabi NOC 500 2009 2013 Gas sweetening facilities project ...... Qatar NOC 600 2010 2013 Mina Al-Ahmadi refinery pipelines 2 ...... Kuwait NOC 400 2010 2013 Water injection project ...... Kuwait NOC 430 2010 2013 Laggan-Tormore gas processing plant ...... UKCS IOC 800 2010 2014 South Yoloten gas plant ...... Turkmenistan NOC 3,400 2011 2013 In Salah southern fields development ...... Algeria NOC/IOC 1,200 2011 2014 Majnoon early production facility ...... Iraq IOC 240 2011 2013 Petro Rabigh Refinery ...... Saudi Arabia NOC Undisclosed 2012 2015 Badra oil field ...... Iraq IOC 330 2012 2015 Jazan oil refinery ...... Saudi Arabia NOC 1,400 2012 2015 KOC Power distribution network ...... Kuwait NOC 200 2012 2014 Upper Zakum, UZ750 field development(3) . . . Abu Dhabi NOC 2,900 2013 2016 Bab gas compression(4) ...... AbuDhabi NOC 500 2013 2016 Bab Habshan-1(4) ...... AbuDhabi NOC 187 2013 2015

(1) Values are based on our share of the original contract value as of the date of award. Exchange rates for non- US dollar denominated contracts are calculated using the exchange rate on the date of the award. (2) The GASCO project is being executed by Petrofac Emirates, in joint venture with GS Engineering and Construction Corp. Petrofac Emirates has a 45% interest in the GASCO project. Petrofac International Ltd has a 75% economic interest in Petrofac Emirates, and Nama Project Services has a 25% economic interest. (3) The Upper Zakum, UZ750 field development is being executed by Petrofac Emirates in consortium with DSME. (4) The Bab gas compression and Habshan-1 projects are being executed by Petrofac Emirates.

We made good progress on our existing portfolio of projects during the six months ended 30 June 2013, including progress on commissioning our major projects such as the Asab oil field development in Abu Dhabi, the El Merk gas processing facility in Algeria and the South Yoloten development in Turkmenistan. Furthermore, a consortium of Petrofac Emirates and Daewoo Shipbuilding & Marine Engineering Co Ltd (“DSME”) was awarded an EPC contract worth approximately US$3.7 billion by Zakum Development Company for the Upper Zakum, UZ750 field development in Abu Dhabi, which is expected to be completed by 2016. Petrofac Emirates’ share of the contract is valued at US$2.9 billion.

In 2012, OEC completed the Kauther gas compression project in Oman, introduced hydrocarbons on the Asab onshore oil field development in Abu Dhabi and substantially completed the Karan project in Saudi Arabia. Furthermore, OEC readied the gas processing facility at the El Merk gas processing facility in Algeria for the commencement of initial production. OEC also achieved an order intake of US$3.0 billion in 2012, including securing major new awards such as the Badra Oil field development in Iraq, the KOC Power Distribution network in Kuwait and the Jazan Oil Refinery in Saudi Arabia.

In 2011, OEC completed the Jihar gas plant in Syria and the In Salah Gas compression facilities and power generation project in Algeria. It also progressed the South Yoloten gas plant in Turkmenistan, the gas sweetening facilities project for Qatar Petroleum and the Mina Al-Ahmadi refinery pipelines 2 project in Kuwait. The OEC reporting segment also achieved an order intake of US$1.6 billion in 2011, including securing new awards for the In Salah southern fields development in Algeria and the Majnoon early production facility in Iraq.

83 OEC’s competition comes from a range of international and more regionally focused contractors, including Saipem and Technip from Europe, JGC Corporation and Chiyoda Corporation from Japan, KBR, Inc. and Bechtel Corporation from the United States and Samsung Engineering Co. Ltd., Daelim Industrial Co. Ltd., SK Engineering & Construction Co. Ltd., Hyundai Engineering & Construction Co. Ltd., Hyundai Heavy Industries Co. Ltd. and GS Engineering & Construction Corp., all of which are from the Republic of Korea. Given the size and technical complexity of the projects being delivered, many contractors including Petrofac often partner with competitors to deliver these projects.

Offshore Projects & Operations The OPO reporting segment has two separate service lines, OPO and OCP. Together, these service lines provide engineering and construction services at all stages of greenfield and brownfield onshore and offshore projects. In addition, through the provision of operations support services, the segment delivers production and maintenance support and services.

OPO’s services include complete facilities management, operations and maintenance support, maintenance strategy development, health, safety and environment regulatory compliance, transition management, logistics and supply chain management, mechanical services, inspection and repair, operations shutdown management and metering services.

The OCP service line was created in June 2012 to expand our EPIC services, which include greenfield development of production facilities, concept and FEED design, project management, procurement, integration management, construction, brownfield modifications and shut-downs, commissioning and start up, decommissioning and FPSO vessel and Floating, Storage and Offloading conversions. Core areas of expertise include: • jacket and topside modules such as reception facilities, separation, power generation, water treatment and disposal, compression, dehydration, launchers, water injection, and gas injection, among others; • subsea pipelines, umbilicals, risers and flowlines; • subsea step-outs and tie-backs; • brownfield modifications; and • FPSO facilities and subsea scopes, including mooring, flowlines and controls.

Currently the majority of OPO’s activities are concentrated in the UKCS, but the service line’s activities include a growing number of locations such as Iraq, Malaysia, Thailand and the UAE. As of 30 June 2013, the OPO segment had 4,998 employees.

The majority of the OPO service line’s activities are provided on a reimbursable basis, often with incentive income linked to the successful delivery of performance targets, whereby costs are charged to the customers together with a fixed margin. In addition, incentive income linked to the achievement of KPIs may be earned. The majority of the contracts entered into by the OCP service line are lump-sum. Many of these contracts have terms of three to five years. In the case of Duty Holder contracts, where we take full responsibility for managing a customer’s asset and are responsible for the safety of that asset, the contract duration is generally for an indefinite period.

For the six months ended 30 June 2013, OPO accounted for 23% of our revenue, 8% of our EBITDA, 7% of our operating profit and 5% of our profit attributable to Petrofac Limited shareholders. In 2012, the OPO reporting segment accounted for 21% of our revenue, 10% of our EBITDA, 10% of our operating profit and 9% of our profit attributable to Petrofac Limited shareholders.

84 The following table sets out OPO’s current key projects.

Offshore/ Value Year Completion Project Customer Location Onshore (US$ millions)(1) Awarded Date Contract Type Sajaa Gas Plant Sharjah UAE Onshore 250 2010 2015 Reimbursable National Oil plus KPIs Company Ithaca Ithaca UK Onshore 540(2) 2011 Open ended Reimbursable Energy and plus KPIs Offshore Apache Apache UK Onshore 480(3) 2012 2015 Reimbursable North Sea and Ltd Offshore Iraq Crude Oil Export South Oil Iraq Offshore 100(4) 2012 2013 Lump-sum Expansion Project Company plus reimbursable Bekok-C Petronas Malaysia Offshore 220 2012 2013 Reimbursable Carigali Sdn Bhd Rumaila(5) BP Iraq Onshore 160 2012 2015 Reimbursable Badra Gazprom Iraq Onshore 95 2013 2016 Reimbursable Oman Operations and Oman Oil Oman Onshore 50 2013 2016 Reimbursable Maintenance Company Sarb 3(6) ADCO Abu Dhabi Offshore 500 2013 2016 Lump-sum

(1) Values are based on our share of the original contract value as of the date of award. Exchange rates for non-US dollar denominated contracts are calculated using the exchange rate on the date of the award. (2) The value for the Ithaca project includes modification and upgrade works done on FPF1 floating production facility and the initial five years of revenue in relation to the subsequent Duty Holder contract. (3) The value stated for the Apache project is for the initial three year contract period. There are two optional one-year extensions, which bring the total potential value of the award to US$800 million. (4) The value stated for the Iraq crude oil export expansion project is for the initial one year contract period. There are two optional one-year extensions, which bring the total potential value of the award to US$298 million. (5) The Rumaila project is being executed through a joint venture agreement with CPECC in which we have a 70% interest and CPECC has a 30% interest. (6) The Sarb 3 project is being executed by the OCP service line.

In the six months ended 30 June 2013, we saw strong activity levels on a number of contracts awarded in the second half of 2012 such as the Apache engineering and construction services contract in the UK North Sea, the offshore operations contract for South Oil Company in Iraq and an inspection, maintenance and repair contract for BP in Iraq on the Rumaila field. We were also active on the upgrade and modification of the FPF 1 for the Greater Stella Area development in the UKCS and the refurbishment of the Bekok-C platform in Malaysia. On 2 April 2013, we were awarded a US$500 million EPIC contract by Abu Dhabi Marine Operating Company for the Sarb 3 project, offshore Abu Dhabi, which is expected to be completed by 2016.

OPO delivered strong activity levels during 2012, from long-term operations support contracts, both onshore and offshore, and from offshore capital projects. The reporting segment achieved an order intake of US$2.2 billion, including onshore maintenance and offshore operations and maintenance projects in Iraq for BP and South Oil Company, respectively; onshore engineering and both onshore and offshore construction services to all of Apache’s UK North Sea assets; and a platform refurbishment contract for Petronas in Malaysia.

We also saw strong activity levels during 2011, from both long-term operations management contracts and offshore capital projects. These projects included the Sepat development and the upgrade and life extension works on the Berantai FPSO, both in Malaysia (both projects being undertaken jointly with OEC). OPO achieved an order intake of US$1.6 billion in 2011, including major new awards, such as the modification and upgrade works to the FPF1 floating production facility ahead of its deployment on the Greater Stella Area development in the Central North Sea.

For operations & maintenance services, OPO competes against a range of international and local companies. In OPO’s main market of the North Sea, the competition is predominantly from AMEC, John Wood Group plc

85 (“Wood Group”) and Aker Solutions ASA, while in other less mature basins OPO also competes with local service providers. OCP is expected to primarily be competing with other offshore EPIC contractors focused on deepwater developments in the long-term, such as Subsea 7, Technip and Saipem. In the short term, OCP is also expected to compete with shallow water focused EPIC contractors, such as National Petroleum Construction Company and McDermott International, Inc. as well as specialist offshore service providers such as Seaway Heavy Lifting, Heerema International Group Services S.A. and Ezra Holdings Limited.

Engineering & Consulting Services ECS acts as our technical engineering centre, providing engineering services across the life cycle of oil and gas assets to both external customers and in support of projects undertaken by other service lines. ECS executes all engineering aspects of a project including the provision of specialist expertise in consultancy, feasibility studies, FEED, detailed engineering, health, safety and environmental studies, value engineering, operability and operational enhancement studies. Areas of expertise include: • onshore/offshore, oil and gas plants, LNG plants and refineries; • full-field development plans with associated technical, commercial and risk studies; • process engineering and flow assurance; • project analysis of costs, schedules and risk management; • subsea pipeline consulting and engineering expertise; and • full project management and services from project concept through delivery.

Furthermore, ECS employs experts in process engineering, dynamic simulation and flow assurance; safety engineering, including quantitative risk analysis and consequence and dispersion modelling; mechanical engineering including rotating machinery and heat transfer; and civil and structural engineering, including geotechnical, concrete and steel structures.

As of 30 June 2013, ECS had 3,633 employees. For the six months ended 30 June 2013, ECS accounted for 6% of our revenue, 2% of our EBITDA, 2% of our operating profit and 3% of our profit attributable to Petrofac Limited shareholders. In 2012, ECS accounted for 4% of our revenue, 4% of our EBITDA, 4% of our operating profit and 4% of our profit attributable to Petrofac Limited shareholders.

In the six months ended 2013, we secured a number of conceptual studies and FEED studies from external customers as well as continuing to support the rest of the internal ECOM and IES projects. In January 2013, we were awarded a substantial consultancy, design and procurement services contract in Algeria by the In Salah Gas and In Amenas joint ventures comprising Sonatrach, BP and Statoil. In March 2013 we were awarded in partnership with DORIS Engineering, a project management contract by PEMEX for their Lakach deepwater development in Mexico. During the six months ended 30 June 2013 we also established overall management control of RNZ, a Malaysian engineering company with particular focus on major offshore engineering projects.

In 2012, ECS was awarded a number of conceptual studies and FEED studies in Africa and the CIS. In addition, the segment acquired KW Limited, a high-end subsea pipeline consulting and engineering services business which will enable us to strengthen our engineering proposition offshore.

In 2011, ECS expanded its presence in Asia Pacific through a collaboration agreement with a Malaysian engineering company, taking our total headcount in Asia Pacific to approximately 1,250. We opened a third Indian office, in Delhi, to support growth in activity levels across the Group. Furthermore, we entered a joint venture with CPECC to provide project management and engineering services on projects for Chinese oil and gas companies in China and internationally.

ECS’s competition ranges from full service engineering companies such as Foster Wheeler AG, AMEC, WorleyParsons Ltd and Aker Solutions ASA to specialist engineers who focus on specific sectors, such as Genesis Oil and Gas Consultants Ltd. which focuses on oil & gas process design and J P Kenny Ltd (part of Wood Group) which focuses on subsea engineering.

ECOM Sales and Marketing ECOM’s global sales and marketing is organised regionally (Americas, Europe, Middle East, Africa, Russia/CIS, and Asia Pacific) as well as by service line (OEC, OPO, OCP and ECS) and has 30 employees. The sales and

86 marketing teams focus on selling across the four ECOM service lines and identify opportunities within the regions and track the project development. As project opportunities often become general knowledge a number of years in advance of the commencement of operations, either as a result of announcements of new licence awards or of resource holders soliciting bids, the ECOM sales and marketing team looks for potential projects up to four years in the future to ensure we are well positioned to convert potential projects into new business. The majority of new opportunities come in the form of competitive bids, and the pipeline is rigorously screened to identify those projects where Petrofac has the best chance of success through technical capability, relationships, local content delivery and pricing while ensuring that we maintain our sector leading margins. For those projects identified, the sales and marketing teams will express our intention to bid, and in many instances undergo a customer pre-qualification process to demonstrate our experience and financial stability. On receipt of a bid, technical and commercial proposals are prepared; submitted to the customer, and following assessment by and negotiation with the customer, we may be awarded the project.

Integrated Energy Services IES helps customers develop their resources through the development of new fields or by enhancing production of mature reservoirs. IES projects cover upstream developments, including greenfield and brownfield projects, and may include related energy infrastructure projects. In appropriate circumstances, we may provide financial capital in addition to expertise. IES is organised into three discrete but integrated service lines: • Developments develops, operates and maintains greenfield projects for resource holders. We will often co-invest in the development and receive returns based upon our performance; • Production Solutions improves production, operational efficiency and recovery from customers’ mature fields, which may involve investment in these field developments; and • Training Services develops and manages capability plans for customers and builds and operates training facilities. In 2012, Training Services managed 14 facilities in seven countries and delivered more than 200,000 delegate days (days in which an individual was present at training), helping create long-term alignment with Petrofac customers.

The IES operations are focused on Asia Pacific, West Africa, UKCS, the Middle East and North Africa, the CIS, Mexico and Romania. As of 30 June 2013, IES had 3,266 employees. For the six months ended 30 June 2013, the IES division accounted for 15% of our revenue, 31% of our EBITDA, 21% of our operating profit and 19% of our profit attributable to Petrofac Limited shareholders. In 2012, our IES division accounted for 11% of our revenue, 22% of our EBITDA, 17% of our operating profit and 14% of our profit attributable to Petrofac Limited shareholders.

The IES division provides its services pursuant to a range of commercial frameworks, including RSCs, PECs and equity upstream investments such as PSCs.

Under the RSC commercial model, we develop, operate and maintain a field while the resource holder retains ownership and control of their reserves. We will often co-invest in the development and receive returns based on performance measures such as delivery timeline and asset operating performance. Depending on the contract, compensation may be received over the life of the project or as we achieve certain milestones. RSCs typically have indirect exposure to commodity prices and reservoir performance.

Under the PEC commercial model, we are paid a tariff per barrel for production, and as a result we do not have any direct commodity price exposure. We invest capital on these production-enhancing activities, which is recovered over the life of the contract through a cost recovery mechanism or a pre-agreed tariff per barrel produced. These contracts are generally long-term contracts for mature fields with a long production history.

Equity upstream investments that we have entered into in the past include concession agreements and royalty agreements in addition to PSCs. These arrangements require that we take a direct interest in the production of a field and as a result we have direct production and commodity price exposure. We use derivative hedging instruments to address the commodity price exposure. Going forward we expect to focus on PECs and RSCs in place of PSCs.

87 The following table sets forth IES’s key projects.

Project & Contract Partners Customers Country Duration Production Enhancement Contracts Ticleni Petrom Romania 2025 Magallanes and Santuario Pemex Mexico 2037 Pánuco Schlumberger Pemex Mexico 2043 Arenque Pemex Mexico 2043 Risk Service Contracts Berantai development Sapura Energy Ventures Sdn Bhd, Petronas Malaysia 2020 Kencana Energy Sdn Bhd (subsidiaries of SapuraKencana) Equity Upstream Investments Block PM304 Petronas Carigali Sdn Bhd, Petrovietnam Malaysia 2026 (30% production share) Investment & Development Company, Kufpec (Malaysia) Limited Chergui gas plant Enterprise Tunisienne D’Activités Tunisia 2031 (45% production share) Pétrolières Greater Stella Area(1) Ithaca Energy (UK) Limited (“Ithaca”), UK Life of field Dyas UK Limited (“Dyas”)

(1) Pursuant to our joint operating agreement with Ithaca and Dyas, we will receive a 20% production share on achieving first oil.

In Mexico, we took over field operations in the Panuco contract area in late March 2013 and the Arenque contract area in early July 2013. We also made good progress on the Magallanes and Santuario blocks, where we have improved production levels from when we took over the assets in February 2012. On the Ticleni PEC in Romania we achieved an increase in production in the six months ended 30 June 2013 compared with the corresponding period in 2012.

On the Berantai RSC, offshore Peninsular Malaysia, by 30 June 2013 we achieved a key milestone by bringing all thirteen wells from the first phase of the development online. On the Etinde Permit in Cameroon, Bowleven completed the appraisal of the IM5 well on the Permit during the first half of 2013, which confirmed the discovery of condensate and gas.

In Malaysia, we commenced production from the third phase of development of Block PM304, West Desaru in early August 2013, eighteen months after approval of the Field Development Programme by Petronas. During the in the six months ended 30 June 2013 we also drilled two new wells on Block PM304 as part of a near field appraisal programme and the results from both wells increased the oil in place. Subsea development drilling operations have also commenced on the Greater Stella Area development in the North Sea during the first half of 2013.

In 2012, the IES division achieved gas exports on the Berantai RSC in Malaysia, following full field development including FPSO topsides upgrade and modification, in less than 21 months. The division also commenced work on the Magallanes and Santuario PECs in Mexico and was awarded a further two PECs for the Pánuco and Arenque areas. The IES division signed a co-operation agreement with Schlumberger in respect of certain types of future IES projects, which will allow it to pursue larger PECs and develop at a faster pace, and entered into a strategic alliance agreement with Bowleven to develop the Etinde Permit in Cameroon, subject to an agreed field development plan and other conditions.

In 2011, the IES division secured an RSC in Malaysia for development of the Berantai field and secured two PECs to develop the Magallanes and Santuario blocks in Mexico. Furthermore, a field development plan was approved by Petronas to develop the third phase of Block PM304, West Desaru in Malaysia.

IES’s business model is relatively new to the market, with only a few NOCs offering service based contracts to develop or improve production from their hydrocarbon resources. The competition is a mixture of other service companies, such as Baker Hughes in Mexico, IOCs, such as Repsol S.A. in Mexico, and small independent oil companies such as Roc Oil who are developing an asset under an RSC in Malaysia. By delivering projects on a service basis, with contract terms that incentivise us to deliver the project on-time and within budget or to

88 continue to increase the production of a field, we are aligned with the interests of the resource holder. By working with us, NOCs are able to access our extensive engineering, project management, delivery and operating experience to develop or improve recovery from resources which they otherwise might not have been able to, while at the same time retaining full ownership of the underlying reserves and developing the local economy and workforce.

IES Sales and Marketing Our IES sales and marketing team is organised on a regional basis, with focal points for the Americas, Europe & Sub-Saharan Africa, Middle East & North Africa, the CIS and Asia Pacific. IES sales and marketing teams efforts are a mixture of responding to formal auction processes, such as those through which IES won the PEC projects in Mexico, and negotiated bi-lateral projects in a small number of focus countries, such as the Berantai RSC project in Malaysia. On every project, the IES sales and marketing teams screen and assess the opportunity through a stage-gated approval process with the IES Business Development team developing the commercial structure and terms of the project to ensure that it meets the required investment criteria.

Corporate Responsibility We believe that corporate responsibility is a practical demonstration of our core values of being safe, ethical, focused on quality, and responsive. In 2012, we developed a roadmap toward achieving integrated reporting to formalise our approach to corporate responsibility. We believe this is particularly important given the recent formation of IES and our strategy of increasing the number of long-term PECs and RSCs, often in developing countries and new geographies. We are in the process of developing KPIs to monitor our social impact.

Safety and Integrity Safety is paramount to us. We work in a technically challenging and geographically diverse industry that requires a vigilant and proactive approach to safeguarding people and property across the world. We believe that the safety of people and of the plants we build and operate is critical to our continued success. The safety function is overseen by the Group Director of Health, Safety, Security, Environment and Integrity Assurance.

Asset Integrity Our Group Integrity Forum is responsible for the oversight of the management of our asset integrity assurance worldwide. This forum, which consists of members of management of all the assets operated by our Group, meets on a quarterly basis and monitors and reviews asset integrity. We conduct periodic audits of major sites to determine compliance with our asset integrity standard and protection against, and preparedness for, major accidents. The information gathered is carefully assessed to check performance and trends and remedial action is taken as required. We continually seek to improve our asset integrity guidelines, which aid us in recognising risks and taking actions to manage them.

Furthermore, each of our operations carries out regular asset integrity assessments, which report against 30 measures covering plant reliability and condition, management of maintenance and assurance activities and organisational matters. Our Asset Integrity Review Board, which meets monthly, assesses operational integrity against these reported measures. The review board involves managers from all operated sites that meet to identify and seek to resolve potential risks. The review board also acts as a valuable forum for peer review and sharing experience.

In 2012, we launched a new asset integrity framework to deliver a structured and consistent approach to asset integrity across all our operations. The framework comprises our asset integrity policy, our asset integrity standard, a number of guidance documents and a toolkit of supporting processes.

Safety Culture We believe that employees must have safety skills and awareness in order to ensure safety in the workplace, in addition to high-performing assets and robust systems. Training is essential to developing these skills and awareness, particularly as a portion of our workforce is recruited locally and is unfamiliar with our industry and safety culture, and we have developed a number of training systems. For example, in 2012 OPO was instrumental in the development of an e-learning programme on safe working practices for offshore staff. The interactive “Control of work” programme uses 3D animations, case studies, lessons learned from previous accidents and offshore videos. This programme is now being widely adopted throughout our industry, including by some of our customers.

89 Furthermore, we have developed a lessons-learned database to enable easy access to a wealth of safety information and to generate alerts around specific incidents or areas of concern, and every year we hold a Safety Managers’ Forum to support the sharing of lessons learnt and best practice internally by bringing together safety and operational managers from across the Group.

We also have a group-wide “Horizon Zero” safety campaign, named after our goal of achieving zero lost time and major incidents. This campaign is intended to educate our employees around our eight “golden rules of safety”. Driving, which remains the primary cause of injury and death in our industry, is a particular focus.

In addition, we work to reduce risk across the wider oil and gas industry by sharing best practice with our peers. We are members of the UK Oil Spill Prevention and Response Advisory Group and support the UK industry’s “Step Change in Safety” initiative. Our specialist operations provide invaluable insights in this field, as Petrofac Training Services is a respected emergency response trainer and our UK Emergency Response Service Centre provides a 24-hour integrated response capability.

Our Safety Performance With respect to incident reporting, we have adopted the Occupational Safety and Health Administration (“OSHA”) guidelines across our group, but also comply with local regulation where that differs from the OSHA standard. The reporting segments provide monthly updates on health, safety and environmental performance. In 2012, 2011 and 2010, approximately 272 million, 143 million and 76 million man-hours, respectively, were completed by our employees and subcontractors. Despite the increase in man-hours completed from 2010 to 2012, our recordable incident frequency rate in 2012 decreased slightly to 0.13 per 200,000 man-hours from 0.14 per 200,000 man-hours in 2011 and 0.18 per 200,000 man hours in 2010. Similarly, the lost time injury frequency rate remained the same in 2012 as in 2011, at 0.018 per 200,000 man-hours, compared with 0.016 in 2010. Our driving incident frequency rate remained level at 0.11 per million kilometres driven in 2011 and 2012, compared with 0.03 in 2010.

In line with our “Horizon Zero” objectives, several sites experienced no lost time injury incidents at all in 2012, in particular the El Merk gas processing facility in Algeria, which achieved 25 million man-hours without lost time injury. Other safety landmarks were achieved at Karan, our gas plant development project in eastern Saudi Arabia, which reached more than 11 million incident-free man-hours; our Mina Al Ahmadi pipeline project in southern Kuwait, which has had over ten million incident-free man-hours, and our oilfield production enhancement operations in Ticleni, south-western Romania, which topped five million incident-free man-hours. Regrettably, there have been three contractor fatalities this year as of 26 September 2013 (being the latest practicable date prior to the publication of this document). In 2012, there were two contract worker fatalities; in 2011, we did not have any fatalities; and in 2010, there was one contract worker fatality. Each fatality was investigated and reviewed by Senior Management and then separately by our Board of Directors.

We consistently focus on developing our emergency response preparedness across the Group, including training and preparedness exercises at both the Group and divisional level. We also regularly revise our crisis management standard to reflect the changing nature of our contracts and our presence in a number of challenging geographies, which we will continue to develop and refine going forward.

Security Our security team, works closely with each reporting segment to protect our people and assets. This is particularly important as, with our growth strategy increasingly taking us into new territories, we work in challenging social and political environments. Our security team monitors each of the countries in which we operate to ensure adequate security measures are in place, including weekly country updates and 24-hour emergency support, and briefs the Board Risk Committee. During 2011 and 2012, our security arrangements allowed us to manage challenges in several locations, including evacuations of a site in Tunisia resulting from unrest in the country. In January 2013, following the terrorist attack at the In Amenas natural gas site in Algeria, at the request of our customer, we evacuated our staff on a temporary basis from the In Salah southern fields development in that country.

Our risk-based Group security management standard provides us with a consistent approach to assessing risks and accordingly enables us to ascribe the relevant precautionary measures to mitigate such risks.

Our security systems, like all areas of our activity, are changing with the evolution of the Company. Reflecting the strategic expansion in our offshore business, in 2012 we drafted a new maritime security standard.

90 Environmental protection We are committed to limiting the environmental impact of our operations around the globe, and follow a systematic approach to environmental management, even in geographies where such standards are not required by law. Many of our locations have ISO 14001 accredited environmental management systems, supported by regular internal inspections and audits. In addition, we are in the process of improving our oil spill response audit programme and expanding our environmental management audits at key sites.

In 2011, we introduced standardised environmental reporting practice across the Group. This enables us to track our total energy consumption, waste, travel, water use and air emissions more accurately. To progress further, we now aim to attain third-party validation of our figures, in line with the Global Reporting Initiative (“GRI”) standard. In 2012, we saw a reduction in our carbon footprint of approximately 11% compared with 2011. This is a result of a reduction in flaring activities in Malaysia as well as changes to our reporting practices to be more in line with GRI standards. In all, our operations, including our share of joint ventures but excluding customer-owned facilities, emitted 201,675 tonnes of carbon-dioxide in 2012 compared with 227,390 tonnes in 2011.

In addition, thousands of our staff are involved in energy saving initiatives. We have a “Think energy. Increase efficiency” campaign aimed at educating and encouraging employees to change their behaviour, at home and at work, to reduce energy use. We also continue to explore ways of cutting carbon emissions, and regularly perform audits on key sites to track emissions and energy use. These programmes have been effective; our Sharjah office, for example, has reduced its energy use and spend by over one-third since 2010, a saving of almost US$390,000.

In 2012, we again participated in the UK Government’s Carbon Reduction Commitment Energy Efficiency Scheme for our assets located in the United Kingdom, complying with all criteria.

Managing Changing Environmental Risks Our environmental steering group, which includes senior operational and functional managers, shapes our approach to environmental management. In 2012, we revised our environmental policy in line with our recently introduced ECOM and IES divisional structure and our evolving business model, including the increase in our offshore activity. Changes included clarifying our commitments to environmental performance and outlining the respective environmental objectives for us and our individual service lines.

As well as measuring our own emissions, we continue to do the same for our customers. Our specialist support includes providing extensive monitoring under the Oslo-Paris Convention environmental management requirements and the European Environmental Emissions Monitoring System.

We remain active members of the Arab Forum for Environment and Development and the Emirates Environmental Group. Looking forward, we intend to revise our environmental standards and overall approach, to ensure our evolving business continues to manage environmental risk effectively and consistently.

Ethics We believe that behaving ethically, in accordance with our Group values, is everyone’s responsibility, and our Code of Conduct sets out the standards of behaviour that we expect from all our employees and others who work for and with us. During 2012, we revised the Code of Conduct to incorporate best practice, reflect new legislation and make it more aligned with the increasing risks that a company operating in multiple jurisdictions encounters. Additions included Q&A sections, guidance on what is expected of employees and third parties, a new equal opportunities chapter, explicit prohibition on the making of facilitation payments and extended sections on working with third parties, covering anti-bribery efforts, conflicts of interest and fair competition.

The new code, which is available on our Group’s intranet and in printed form, encourages employees and third parties to report breaches of the Code of Conduct through various means, including a whistle-blowing line, with free, confidential 24-hour national phone lines.

Compliance Our compliance agenda is delivered on a decentralised basis by our ECOM and IES divisions with guidance from the Compliance function, which is run out of London. Our compliance team sets policies, procedures and processes but implementation, such as the identification and mitigation of compliance risks occurs locally. In order to understand the issues that may occur in the businesses, our two divisions both have compliance managers.

91 Our Code of Conduct and management standards require observance of all applicable legislation, including trade and export regulations. We continue to embed these in our business, including refining our third-party screening process to differentiate between types of suppliers, from joint venture partners to sub-contractors to those who work with third parties on our behalf. We also monitor gifts and entertainments received by employees, and continue to educate our workforce on the prevention of bribery and corruption.

Risk Management We believe that management of risk is a crucial element of our competitive advantage, and we have established procedures to provide that significant risks to our reputation and shareholder value are appropriately monitored and mitigated in line with the Board’s policy.

Our objectives for managing risk are: • to create an environment which promotes the long-term sustainable growth of the Group; • to articulate clear policy standards and deploy effective and efficient processes; • to define clearly ownership and responsibilities for managing risk across the Group; • to create a risk-aware culture across the Group by informing, training and motivating employees to consider risk within their day-to-day decision making; • to deploy effective project risk management processes and controls across all business service lines; and • to provide transparency on our risk management approach to our Board and other key stakeholders.

Risk Governance Framework Our system of risk governance relies on a number of committees and management processes which bring together reports on the management of risk at various levels. The governance process relies upon regular risk assessments and reviews of existing and new opportunities, and considering the risk exposure and appetite of each reporting segment, service line and function. The description below sets out the risk governance structure in operation, showing the interaction between the various risk review and management committees. Terms of reference are in place for each individual committee.

The Board The Board of Directors retains ultimate responsibility for setting our risk tolerance and reviewing the risks which the Board considers sufficiently significant that they might prevent the delivery of strategy or threaten our continued existence. The Board reviews risks at every scheduled Board meeting, focusing particularly on project execution risks.

The Board Risk Committee The Board Risk Committee is comprised of four Directors, and assists the Board in discharging its risk management responsibilities. The Committee has responsibility for providing oversight and advice to the Board on the current risk exposures and future risk strategy and in doing so, is responsible for making recommendations to the Board in relation to our Enterprise Risk Management (“ERM”) framework (see “—Enterprise Risk Management System” below), our risk tolerance in pursuit of business objectives; and recommending approval of the Delegations of Authority (“DoA”). The Committee also assists the Board with the definition and execution of an effective risk management strategy and has responsibility for oversight of the Company’s compliance system of corporate standards, processes and procedures. In addition, the Committee provides the Board with assurance, on an annual basis, that the design and operating effectiveness of these systems remain fit for purpose.

The Group Risk Committee The Group Risk Committee (“GRC”) is a management committee constituted as the principal executive forum for the review of enterprise, project and investment risks, in accordance with the DoA approved by the Board. The GRC reviews material new business opportunities and projects (including bid submissions, country entry, joint ventures, investments, acquisitions and disposals), and is responsible for making recommendations as to the management and mitigation of risk exposure. The GRC is responsible for the assurance of the ERM framework agreed by the Board, including the approval of Group standards and the application of the Board’s DoA.

92 Divisional Risk Review Both ECOM and IES have a Divisional Risk Review Committee, each chaired by that division’s Chief Executive. The Risk Review Committees provide peer review of proposed projects and investments in accordance with the DoA approved by the Board. The committees review the risks and mitigation strategies in respect of new business opportunities or projects. Where required by the DoA, these committees then prepare appropriate materials for the GRC. No proposal is presented to the GRC without having first been reviewed and supported by the Divisional Risk Review Committee.

Service Line Review Each of our individual service lines has its own business management system that incorporates risk management policies and procedures and produces its own risk register. Each service line’s management team meets regularly and monitors risk as a matter of course, notes any change in risk assessment and seeks to take appropriate mitigating action. The risk registers for each service line are formally reviewed each month by that business’ senior leadership team.

Enterprise Risk Management System Recognising the evolving regulatory landscape and aiming to support our strategy for growth, the Board Risk Committee commenced the ERM programme in 2011 and has continued to develop the programme in 2012 with the appointment of a new Group Head of Enterprise Risk. Plans for further developing the ERM programme include engaging and communicating on risk more effectively; bringing greater clarity to our risk management strategy and risk management framework.

Enterprise risk profile The key risks that could lead to a significant loss of reputation or prevent us from delivering our strategic plan are captured in our enterprise risk profile which is updated quarterly. The enterprise risk profile is the means by which enterprise risks are reported to the Board Risk Committee.

Our enterprise risk profile is assessed through Key Risk Indicators, which record exposure to potentially harmful events. The enterprise profile seeks to identify and measure risk across risk types and monitor emerging trends and exposures.

Key Risk Register We are in the process of creating a Key Risk Register comprising all our “critical” and “significant” risks. The purpose of this is to (i) map specific risks to the risk profile making those relationships more explicit; and (ii) promote and support the active management of important risks. The register will provide further clarity around ownership, accountability and mitigation strategies.

Employees The following table provides a breakdown of our employees by segment for the periods indicated:

As of 30 June As of 31 December 2013 2012 2011 2010 Onshore Engineering & Construction ...... 6,565 7,834 6,678 5,445 Offshore Projects & Operations ...... 4,998 4,342 4,085 4,405 Engineering & Consulting Services ...... 3,633 2,774 2,359 1,826 Integrated Energy Services ...... 3,266 2,979 2,249 2,138 Other ...... 103 102 81 62 Total ...... 18,565 18,031 15,452 13,876

We have a strong culture of employee engagement directly encouraged throughout and with our workforce. However, in terms of relationships with external trade unions (and other related formal bodies) we only have collective labour agreements governing employee terms and conditions, and policy and practice for employees working in Ticleni, Romania and Shetland Islands, United Kingdom. These agreements clearly define the roles

93 and activities of the relevant parties and negotiations and agreements are carried out accordingly. We recognise and have registered agreements with trade unions in Mexico and offshore UK which do not have influence on overall policy and related frameworks but allow local operations to benefit through working with these parties in line with local practice.

Intellectual Property and Information Technology Intellectual Property We have sought to secure rights in certain of our intellectual property to protect our brand and operation. We have registered the Petrofac name and droplet oil logo in numerous countries globally, including most notably, the Middle East, central and south-east Asia and parts of Africa. Caltec Limited, a wholly owned subsidiary of Petrofac UK Holdings Limited, owns a number of patents protecting its technology and processes. Our training business, Petrofac Training Services Limited, also owns intellectual property following its acquisition of Oilennium Limited, a specialist e-learning provider to the energy industry and also SkillsXP, a competency and certification services company. We take seriously any suspected or actual infringement of our brand or other intellectual property.

Information Technology We leverage the capabilities of leading technology providers to provide IT services to us. We employ 350 IT professionals who develop and deliver our corporate IT systems and enable the technologies we use for our customer projects and global operations. Our enterprise applications (including Oracle ERM) are run from IT hubs that allow round-the-clock access to our information systems and critical applications.

Property, Plant and Equipment Our operations own and lease various assets, ranging from rental properties to infrastructure to floating production vessels. The following table sets forth certain material property, plant and equipment as of 30 June 2013:

Country Asset Type Net Book Value (US$ millions) IES Fixed Assets Malaysia Drilling and Equipment 73 Malaysia Infrastructure—offshore drilling wells 181 Malaysia Floating vessel 57 Mexico Infrastructure—wells and equipment 155 Thailand Floating vessel 35 Tunisia Gas plant 52 Romania Infrastructure—wells and equipment 115 N/A Un-deployed vessel 41 ECOM Fixed Assets Sharjah Freehold land & buildings—Tower 1 Office Building 29 Sharjah Freehold land & buildings—Tower 2 Office Building 40

Insurance Overview We maintain an insurance programme to provide mitigation against significant losses, consistent with general industry practice. The majority of our annually renewable insurance coverage is managed through our London office by the Group Insurance Manager, supported by Aon Limited, our corporate insurance broker and advisor. In addition, insurance coverage for specific projects is provided in accordance with the contractual terms agreed with our customers. In the majority of cases project cover is provided under our customers’ policies, but where this is not the case, cover is arranged by the relevant service line supported as required by the Group Insurance Manager.

We believe that our existing insurance coverage is appropriate and covers all general material risks associated with our operations that are usually insured and is in accordance with industry standards.

94 Annually Renewable Policies We maintain corporate insurance to cover our general insurance requirements, including Property Damage and Business Interruption, Terrorism, Marine Transit, Employers’ and Third Party and Public Liability, in addition to Professional Indemnity and Directors and Officers Liability Insurance (“D&O Insurance”).

We also maintain an Energy Package Insurance policy, which covers oil field property, control of well/operators’ extra expenses and associated third-party liability risks, for onshore and offshore activities. The Energy Package insurance policy also includes our owned offshore marine vessels, which are also covered under a separate Protection and Indemnity Club entry for pollution and marine vessel liability exposures.

In addition to the primary liability cover provided under our annual and project liability policies, a separate Umbrella Liability policy exists, to provide catastrophe coverage against onshore and offshore liability risks.

Project Policies For the majority of our EPC projects, particularly projects undertaken by OEC, we are typically the beneficiary of Construction All Risks insurance cover provided by our customers, covering both the EPC risks and the associated third-party liabilities. The terms and limits of these policies are determined by the relevant customer. On the occasions where we purchase our own Construction All Risks insurance policies for onshore and offshore EPC projects, the policies are based on industry standard wordings, to the full Estimated Contract Value (“ECV”).

Insured Limits The policy limits applicable to the various insurance policies are determined by the reinstatement property values, based on external physical asset valuation reports. In respect of Construction All Risks policies, the ECV is calculated by the project team and applied as a policy limit, whilst the potential third party, pollution and D&O Insurance policy limits are determined, having assessed industry standard metrics and following advice from professional advisers, with their knowledge of the Group’s activities. The adequacy of our limits are regularly reviewed and adjusted to reflect the changing risk profile of our activities.

Local Policies In order to fully comply with the local legislative requirements in countries where we operate, locally compliant policies are arranged as necessary and this is continually reviewed as we enter new territories, increase our presence in existing counties or in response to amendments to the local legislation relating to the placement of insurance policies.

Legal Proceedings From time to time we do become party to claims and lawsuits incidental to the ordinary course of our business. We are not currently, and have not been within the last 12 months, involved in any governmental, legal or arbitration proceedings that have had or may have a significant effect on our financial position and, to our knowledge, no such governmental, legal or arbitration proceedings or administrative or regulatory investigations are currently threatened.

95 DIRECTORS AND SENIOR MANAGEMENT

We are governed by resolutions of our shareholders taken at our Annual General Meeting, by acts of our Board of Directors and by our Senior Management team.

Board of Directors Our board of directors (the “Board of Directors” or the “Board”) is responsible for our general management, including the setting of our strategy and coordination and general supervision, with the exception of those matters that are designated by law or by our memorandum and articles of association as being the exclusive responsibility of our shareholders. Our Board of Directors normally meets six times a year and makes its decisions by simple majority. In the year ended 31 December 2012, our Board met six times in scheduled meetings. In addition, our Board of Directors met on an ad hoc basis on a number of occasions, either face-to-face or telephonically, where items of business arose which could not be held over until the next scheduled meeting. Our Board of Directors is currently composed of five executive directors and six non-executive directors, and Mr. Norman Murray, non-executive chairman. The chairman of our Board of Directors has primary responsibility for leading our Board of Directors and ensuring its effectiveness. Ayman Asfari is our Group Chief Executive and is responsible for the implementation and execution of strategy and the day-to-day management of the Group. He is supported by his fellow executive directors and the Senior Management team, which is described in more detail below.

The following table sets forth the name, age, position and year of appointment of each member of our Board of Directors as of the date of this Offering Memorandum:

Year Appointed Name Age Title to Board Norman Murray 65 Non-executive Chairman 2011 Ayman Asfari 55 Group Chief Executive 2002 Maroun Semaan 57 President 2002 Marwan Chedid 52 Chief Executive, Engineering, Construction, Operations & 2012 Maintenance Andy Inglis 54 Chief Executive, Integrated Energy Services 2011 Tim Weller 50 Chief Financial Officer 2011 Thomas Thune Andersen 58 Non-executive Director 2010 Stefano Cao 61 Non-executive Director 2010 Roxanne Decyk 60 Non-executive Director 2011 Kathleen Hogenson 53 Non-executive Director 2013 René Médori 55 Non-executive Director 2012 Rijnhard van Tets 66 Non-executive Director; Senior Independent Director 2007

Board Practices Our Board of Directors is assisted by four committees. Each committee is responsible for reviewing and overseeing activities within its particular terms of reference. At each scheduled Board meeting, the chairman of each committee provides a summary of any committee meeting held since the previous board meeting and the minutes of all committee meetings are circulated to the Board of Directors. Our board committees include the nominations committee, audit committee, board risk committee and remuneration committee. In addition to the four board committees, there are a number of executive management committees which have been established to consider various issues involved in our day-to-day operational management and matters for recommendation to the Board of Directors and its committees.

Nominations Committee The nominations committee reviews the composition and structure of the Board of Directors and its committees, identifies and recommends for the board’s approval suitable candidates to be appointed to the Board of Directors and considers succession planning for directors and other senior executives. The nominations committee is chaired by Mr. Murray, and is composed of Mr. Asfari, Mr. Thune Andersen, Mr. Cao, Ms. Decyk, Ms. Hogenson, Mr. Médori and Mr. van Tets.

96 Audit Committee The audit committee monitors the integrity of our financial statements and reviews our financial and regulatory compliance controls. The audit committee is chaired by Mr. Médori, and is composed of Mr. Thune Andersen, Ms. Hogenson and Mr. van Tets.

Board Risk Committee The board risk committee oversees our risk management and internal control processes for non-financial matters. The board risk committee is chaired by Mr. Cao, and is composed of Ms. Decyk, Ms. Hogenson, Mr. Médori, Mr. Thune Andersen, and Mr. van Tets.

Remuneration Committee The remuneration committee determines and agrees remuneration policy, sets individual compensation levels for all executive directors and the chairman and determines remuneration for certain members of our Senior Management team. The remuneration committee is chaired by Mr. Thune Andersen, and is composed of Mr. Cao and Ms. Decyk.

Biographical Information Norman Murray. Mr. Murray was appointed Chairman in May 2011. Prior to his portfolio career, Mr. Murray spent 25 years in the venture capital industry. He co-founded Morgan Grenfell Private Equity Limited and was also a director of Morgan Grenfell Asset Management Limited. Until June 2011, he was chairman of Cairn Energy plc, having served on that board for 12 years. In February 2012, Mr. Murray stepped down as Non-executive Director of Robert Wiseman Dairies plc. He then stepped down from the board of Greene King plc in December 2012. Mr. Murray is a former chairman of the British Venture Capital Association and a past president of the Institute of Chartered Accountants of Scotland. Mr. Murray is chairman of the Edrington Group Limited.

Ayman Asfari. Mr. Asfari was appointed Group Chief Executive in January 2002. Mr. Asfari joined us in 1991 to establish Petrofac International Ltd, of which he was CEO. He has more than 30 years’ experience in the oil and gas industry, having formerly worked as managing director of a major civil and mechanical construction business in Oman. Mr. Asfari is a member of the board of trustees of the American University of Beirut, founder and Chairman of the Asfari Foundation and member of the Senior Panel of Advisors of Chatham House.

Maroun Semaan. Mr. Semaan was appointed to the Board in January 2002. He became President in January 2012, having previously served as Group Chief Operating Officer. Mr. Semaan joined us in 1991 to establish Petrofac International Ltd. Prior to joining us, he managed oil and gas pipeline, process facilities and civil works construction contracts in Oman and Bahrain, with the Consolidated Contractors International Company (“CCC”). Mr. Semaan is a member of the board of trustees of the American University of Sharjah and a founding member of the board of trustees of the Arab Forum for Environment and Development. On 24 July 2013, Mr. Semaan announced his intention to retire and step down from the Board at the end of 2013.

Marwan Chedid. Mr. Chedid was appointed Chief Executive, ECOM in January 2012. Mr. Chedid joined us in 1992 when the business was first established in Sharjah, having previously worked for CCC, a major consolidated contractor company based in the Gulf and the Middle East, for eight years. In 2007, he was appointed chief operating officer of the Engineering & Construction International business, with day-to-day responsibility for the successful delivery of overall operations. In January 2009, he became managing director of Engineering & Construction Ventures before being appointed as Chief Executive, ECOM.

Andy Inglis. Mr. Inglis was appointed Chief Executive, IES in March 2011. Mr. Inglis joined us in January 2011, having spent 30 years with BP, latterly as CEO of its exploration and production business. He was an executive director on the BP plc board between 2007 and 2010. He started his BP career as a project engineer on various North Sea projects, followed by commercial and operating roles in BP’s upstream business. He became executive vice president and deputy chief executive of BP exploration & production in 2004. He is a former non-executive director of BAE Systems plc.

Tim Weller. Mr. Weller was appointed Chief Financial Officer in October 2011. Mr. Weller joined us in September 2011 from Cable & Wireless Worldwide, where he had been chief financial officer between May

97 2010 and July 2011. A fellow of the Institute of Chartered Accountants in England and Wales with a degree in Engineering Science, he started his career with KPMG in London, eventually becoming a partner in KPMG’s Infrastructure Business Unit. Until May 2010, he was chief financial officer at United Utilities Group PLC and had previously held chief financial officer roles with RWE Thames Water Limited and Innogy Holdings PLC (now RWE npower Holdings PLC) from 2002 to 2006. Mr. Weller became a non-executive director of G4S plc in April 2013 and is a non-executive director of the Carbon Trust. He stepped down from the board of directors of BBC Worldwide in March 2013.

Thomas Thune Andersen. Mr. Thune Andersen was appointed Non-executive Director in May 2010. Mr. Thune Anderson spent 32 years at the A.P. Møller-Mærsk Group with an international career ending as CEO and president of Mærsk’s oil and gas company. He also served on Mærsk’s main board and its executive committee from 2005 to 2009. Since 2009, Mr. Thune Andersen has a board portfolio in companies in the energy and critical infrastructure sectors. Mr. Thune Andersen is Chairman of the Lloyd’s Register Group and Chairman of the Board of Trustees for the Lloyd’s foundation. He is also Chairman of DeepOcean Group, Vice Chairman of VKR Holding and a non-executive director of SSE plc.

Stefano Cao. Mr. Cao was appointed Non-executive Director in May 2010. Mr. Cao has 32 years’ experience in the oil & gas industry. From February 2009 to July 2012, he served as CEO of Sintonia SA, a holding company owning infrastructure assets, including toll roads, airports and telecoms. From 2000 to 2008, Mr. Cao was chief operating officer of Eni’s exploration & production division, before which he spent 24 years at Saipem, the international oil & gas services group, holding such senior roles as CEO, chairman and chief operating officer. During 2012, Stefano was appointed a director of A2A SpA, the largest Italian multi-utility company. Mr. Cao is also a director of the boards of Autostrade per l’Italia SpA and Aeroporti di Roma SpA.

Roxanne Decyk. Ms. Decyk was appointed Non-executive Director in March 2011. Ms. Decyk retired from The Royal Dutch Shell Group in December 2010 having held a number of roles including head of global government affairs and corporate affairs director over a period of 11 years. She was a member of Shell’s executive committee from 2005 to 2009. Prior to joining Shell, Ms. Decyk had various roles at Amoco Corporation and Navistar International Corporation. Ms. Decyk is an independent director of Snap-on Incorporated, Aliant Techsystems Inc. and was appointed as a non-executive director of Ensco Plc on 20 May 2013. She was also appointed to the Defense Business Board, which provides the US Secretary and Deputy Secretary of Defense with independent advice on best business practices for application to the US Defense Department.

Kathleen Hogenson. Ms. Hogenson was appointed Non-executive Director in August 2013. Ms. Hogenson has 30 years’ experience in the oil and gas industry, with particular expertise in reservoir management and subsurface engineering. Ms. Hogenson spent her early career as a petroleum and reservoir engineer, including posts in Ecuador, and is the President and CEO of her own US-based company Zone Energy LLC. Ms. Hogenson currently sits on the advisory board for Samsung Oil & Gas USA Corporation, is a director on the Board of Parallel Petroleum LLC and serves as a trustee of the Society of Exploration Geophysicists.

René Médori. Mr. Médori was appointed Non-executive Director in January 2012. Mr. Médori was group finance director of the BOC Group plc between June 2000 to May 2005, having held several finance appointments, including as finance director of BOC’s gases business in the Americas, from 1997. Mr. Médori stepped down as a non-executive of SSE plc in June 2012. Mr. Médori is finance director of Anglo American plc, a position he has held since September 2005, and a non-executive director of De Beers and Anglo Platinum Limited.

Rijnhard van Tets. Mr. van Tets was appointed Non-executive Director in May 2007 and became the Senior Independent Director in May 2011. Mr. van Tets is general partner of Laaken Asset Management NV. He advised the managing board of ABN AMRO between 2002 and 2007, having previously served as a managing board member for 12 years. At ABN AMRO, his roles included that of chairman of the wholesale customers and investment banking group. Mr. van Tets is non-executive chairman of Euronext NV and a non-executive director of NYSE Euronext Inc. He is also Chairman of the Board of Euronext Amsterdam NV and Arcadis NV, and a board member of BNP Paribas OBAM NV.

Senior Management Team Our Senior Management team consists of nine members and is responsible for the day-to-day management of our operations. Senior Management is also responsible for managing our assets to maximise their value and returns, improving the efficiency of internal control and risk management systems, and ensuring the protection of shareholder rights and interests.

98 The following table sets forth the name, age, position and year of appointment of each member of our Senior Management team as of the date of this Offering Memorandum:

Name Age Title Subramanian Sarma 55 Managing Director, Onshore Engineering & Construction Bill Dunnett 51 Managing Director, Offshore Projects & Operations Yves Inbona 55 Managing Director, Offshore Capital Projects Craig Muir 48 Managing Director, Engineering & Consulting Services Gordon East 50 Managing Director, Production Solutions Paul Groves 53 Managing Director, Training Services Rob Jewkes 57 Managing Director, Developments Richard Milne 58 Group Director of Legal and Commercial Affairs Geoff Tranfield 46 Group Director of Human Resources

Biographical Information Subramanian Sarma. Mr. Sarma is the Managing Director, Onshore Engineering & Construction. Mr. Sarma joined us in 1997 as a project manager and has held various positions since then including Executive Vice President Projects and Deputy Chief Operating Officer of Petrofac International Ltd. As Managing Director of Onshore Engineering & Construction within ECOM, Mr. Sarma is responsible for all our onshore EPC projects worldwide, which are delivered predominantly under lump-sum turnkey commercial models, and a workforce of around 7,800. Prior to joining us, Mr. Sarma worked for Kvaerner and Jacobs in India and Oman and has more than 30 years’ experience in the oil and gas industry.

Bill Dunnett. Mr. Dunnett is the Managing Director, Offshore Projects & Operations. Mr. Dunnett has over 26 years’ experience in the oil and gas industry. He joined us in 2007 initially in the Developments business where he had responsibility for asset development and production, including the Don fields in the UKCS and the Chergui field in Tunisia. Prior to joining us, Mr. Dunnett spent eight years at Halliburton and its subsidiary KBR, as a senior vice president and corporate officer. His responsibilities included membership of the KBR Executive Leadership Team, Global Operations and Maintenance. Mr. Dunnett spent his earlier career with Mobil North Sea and Shell.

Yves Inbona. Mr. Inbona was appointed Managing Director, Offshore Capital Projects in June 2012. Mr. Inbona has extensive expertise in the offshore sector, having more than 30 years of industry experience. Prior to joining us, Mr. Inbona worked as Chief Operating Officer of Saipem SpA, where he managed the offshore business.

Craig Muir. Mr. Muir was appointed Managing Director, Engineering & Consulting Services in February 2012. Mr. Muir previously held the position of executive vice president within growth regions covering the Middle East, Africa and CIS for AMEC, based in Abu Dhabi. His key focus was in the growth of engineering services and Project Management Contracts. Prior to joining AMEC, he also held numerous roles working in the oilfield service sector including those with KBR, Brown & Root and AOC International. He has previously worked in the North Sea, extensively in the Middle East, and in Asia Pacific.

Gordon East. Mr. East is the Managing Director, Production Solutions. Mr. East originally joined us in 2006 as Managing Director of Petrofac Facilities Management (now OPO). Prior to joining us, Mr. East spent more than 20 years with ConocoPhillips in various leadership and management roles throughout the upstream business worldwide. He has also held non-executive roles in the DTI and Cabinet Office.

Paul Groves. Mr. Groves joined us in 2006 and is the Managing Director, Training Services. Mr. Groves previously worked for Shell from 2001, where he held a number of business development-led roles within the organisation. A Chartered Engineer and Scientist, Mr. Groves started his career as a lecturer of physics at Oxford University before moving into a number of management and development roles in organisations such as Alcan Aluminium Limited and British Gas/BG PLC.

Rob Jewkes. Mr. Jewkes joined us in 2004 and is the Managing Director, Developments. Mr. Jewkes is responsible for leveraging our engineering and project management capability through RSCs and equity investments to lead the development of our customers’ upstream assets and energy infrastructure assets. Mr. Jewkes has more than 35 years of experience in the oil and gas industry. Prior to joining us, he served as chief executive officer of Clough Engineering, the main operating company of the Australian engineering group, Clough Limited.

99 Richard Milne. Mr. Milne joined us in 2004 and is the Group Director of Legal and Commercial Affairs. He played a significant role in our successful admission to listing on the London Stock Exchange in 2005 and in developing our governance and compliance framework. As a member of the Senior Management team, Mr. Milne participates in our risk review process and advises on corporate matters in addition to commercial issues. Prior to joining us, Mr. Milne spent some 15 years in corporate finance which followed a career in the insurance brokerage industry. Mr. Milne qualified as a solicitor.

Geoff Tranfield. Mr. Tranfield joined us in 2008 as the Group Director of Human Resources and will resign from the Group with effect from 13 December 2013. Mr. Tranfield previously worked for Hess Corporation for more than five years, latterly in the position of vice president HR—worldwide E&P. Prior to joining Hess, Mr. Tranfield held a number of other HR positions in sectors including oil and gas, utilities and rail.

Compensation Remuneration of the members of the board of directors amounted to US$11.04 million for the year ended 31 December 2012. Remuneration consists of base salary, benefits, cash in lieu of pension, annual bonus and post-employment benefit. In 2012, Non-executive Directors received a basic fee of £63,000 per annum, and an additional fee of £15,000 per annum for acting as a Chairman of a Board Committee.

Remuneration of the members of Senior Management amounted to US$8.5 million for the year ended 31 December 2012. Remuneration consists of base salary, benefits, cash in lieu of pension and annual bonus.

Interests of Directors and Related Party Transactions Interests of Directors As of 26 September 2013 (being the latest practicable date prior to the publication of this document), there are no outstanding transactions other than in the ordinary course of business undertaken by us, or as referred to under “—Related Party Transactions”, in which our Directors were interested parties. Certain of our Directors have direct or beneficial interests in our ordinary shares. As of 26 September 2013 (being the latest practicable date prior to the publication of this document) our Directors owned a combined total of 92,820,831 shares. See also “Principal Shareholders”.

Related Party Transactions The following table provides the total amount of transactions which have been entered into with related parties for the periods indicated:

Six Months Ended 30 June Sales to Related Purchases from Amounts Owed by Amounts Owed to Parties Related Parties Related Parties Related Parties 2013 2012 2013 2012 2013 2012 2013 2012 (unaudited) (US$ millions) Joint ventures ...... 6 85 — 87 29 4 1 58 Associates ...... — 1 — — — 6 — — Key management personnel interests ...... — — — 1 — — — —

Year Ended 31 December Sales to Related Purchases from Amounts Owed by Amounts Owed to Parties Related Parties Related Parties Related Parties 2012 2011 2010 2012 2011 2010 2012 2011 2010 2012 2011 2010 (audited) (US$ millions) Joint ventures ...... 170 323 101 135 187 89 5 95 — 38 23 11 Associates ...... 3 14 ———— 174———— Key management personnel interests ...... — — — 2 2 2 ————— 1

All sales to and purchases from joint ventures are made at normal market prices and the pricing policies and terms of these transactions are approved by our Senior Management. All related party balances are settled in cash.

100 Purchases in respect of key management personnel interests, consisting of members of our Board and Senior Management, were US$0.3 million and US$0.6 million for the six months ended 2013 and 2012, respectively, and US$1.5 million, US$1.4 million and US$1.6 million for the years ended 31 December 2012, 2011 and 2010, respectively, reflecting the costs of chartering the services of an aeroplane used for the transport of Senior Management and Directors on company business. The aeroplane is owned by an offshore trust of which the Group Chief Executive of the Company is a beneficiary. For the six months ended 30 June 2013 and the year ended 31 December 2012, the charter rates charged for Group usage of the aeroplane were significantly less than comparable market rates.

Also, included in purchases in respect of key management personnel interests were US$0.1 million and US$0.1 million for the six months ended 2013 and 2012, respectively, and US$0.2 million, US$0.2 million and US$0.1 million for the years ended 31 December 2012, 2011 and 2010, respectively, relating to client entertainment provided by a business owned by a member of the Group’s key management personnel.

Directors and Officers Insurance We provide indemnities to our Directors in respect of liabilities which may be incurred as a result of their office, in accordance with our Articles of Association and to the maximum extent permitted by Jersey law. We have appropriate insurance coverage in respect of legal action which may be brought against our Directors and officers. Neither our indemnities nor insurance would provide any cover where a Director or officer was found to have acted fraudulently or dishonestly.

Conflicts of Interests None of the members of our Board of Directors or Senior Management team have been subject to any bankruptcy, receivership or liquidation proceedings, nor have any of them been convicted of any fraudulent offence or been subject to any official public incrimination or sanctions by statutory or regulatory authorities (including designated professional bodies) in acting as founder, director or senior manager of any company for the last five years, nor has any of them been disqualified by a court from acting as a member of the management or supervisory bodies of an issuer or from acting in the management or conduct of the affairs of any issuer for the last five years.

Other than described in “—Interests of the Directors and Related Party Transactions—Related Party Transactions”, we are not aware of any potential conflicts of interest between the private interests or other duties of members of the Board of Directors or Senior Management team of the Company and their duties to the Company.

Processes and procedures are in place that require Directors to identify and declare actual or potential conflicts of interest, whether matter-specific or situational. These notifications are required to be made by the director concerned prior to, or at, a board meeting. All Directors have a duty to update the whole board of any changes. The Board may authorise potential conflicts which can be limited in scope, in accordance with our Articles of Association.

101 PRINCIPAL SHAREHOLDERS

Share Capital As of 26 September 2013 (being the latest practicable date prior to the publication of this document), we had an issued share capital of US$7 million comprised of 345,912,747 ordinary shares with a par value of US$0.02 per share.

Shareholders As of 26 September 2013 (being the latest practicable date prior to the publication of this document), members of our Board of Directors (including Ayman Asfari and Maroun Semaan) owned a combined total of 92,820,831 shares. As of 26 September 2013 notifications had been received of the following interests in 3% or more of the Company’s issued ordinary share capital:

Percentage of Issued Ordinary Share Name Shares Capital Ayman Asfari and family ...... 62,950,678 18.20% Maroun Semaan and family ...... 28,288,813 8.18% Total ...... 91,239,483 26.38%

102 THE GUARANTORS

Selected Company and Guarantor Information The Company is a holding company and has no independent operations. As of 31 December 2012, the Company had consolidated net assets of US$1,550 million. The Financial Statements of the Company contain information both of guarantor and non-guarantor companies.

The Guarantors are Petrofac International Ltd and Petrofac International (UAE) LLC. Petrofac International Ltd is a wholly-owned consolidated subsidiary of Petrofac Limited and Petrofac International (UAE) LLC is a 99% owned, consolidated subsidiary of Petrofac International Ltd.

For the year ended 31 December 2012, the Guarantors had EBITDA of US$699 million, which represented 79% of the Group’s EBITDA. As of 31 December 2012, the Guarantors had net assets of US$985 million, which represented 64% of the Group’s net assets.

For the year ended 31 December 2012, our non-guarantor subsidiaries had EBITDA of US$189 million, which represented 21% of the Group’s EBITDA. As of 31 December 2012, our non-guarantor subsidiaries had net assets of US$565 million after eliminating intercompany investments and balances, which represented 36% of the Group’s net assets.

Petrofac International Ltd Petrofac International Ltd, which is a Guarantor, was incorporated on 29 July 1991 as a private limited company under the laws of Jersey with registered number 50698. Its registered office is Ogier House, The Esplanade, St Helier, Jersey JE4 9WG. Petrofac International Ltd is a wholly-owned subsidiary of the Company.

Petrofac International Ltd had EBITDA on a consolidated basis for the year ended 31 December 2012 of US$699 million, which represented 79% of the Group’s EBITDA. Petrofac International (UAE) LLC is a consolidated subsidiary of Petrofac International Ltd, and Petrofac International Ltd, without accounting for Petrofac International (UAE) LLC, had EBITDA for the year ended 31 December 2012 of US$105 million, which represented 12% of the Group’s EBITDA. As of 31 December 2012, Petrofac International Ltd had net assets on a consolidated basis of US$985 million after eliminating intercompany investments and balances, which represented 64% of the Group’s net assets. Without accounting for Petrofac International (UAE) LLC, Petrofac International Ltd had net assets of US$396 million, which represented 26% of the Group’s net assets.

As set out in its memorandum and articles of association, Petrofac International Ltd has unlimited corporate capacity.

There are no risks specific to Petrofac International Ltd or any encumbrances on its assets that could materially affect its ability to meet its obligations under the Guarantee, except as disclosed in “Risk Factors”.

There has been no material change in Petrofac International Ltd’s contribution to the Group’s EBITDA or net assets since 31 December 2012. As of 26 September 2013 (being the latest practicable date prior to the publication of this document), Petrofac International Ltd had no outstanding issued notes or bonds, although it is a guarantor of the Revolving Credit Facility described under “Operating and Financial Review—Liquidity and Capital Resources—Indebtedness—Revolving Credit Facility”.

Petrofac International (UAE) LLC Petrofac International (UAE) LLC, which is a Guarantor, was incorporated on 21 October 2008 as a private limited liability company in accordance with the laws of the UAE with registered number 569307. Its registered office is Petrofac House, Al Khan Road PO Box 23467, Sharjah, United Arab Emirates. Petrofac International (UAE) LLC is a consolidated subsidiary of Petrofac International Ltd, and is wholly-owned subsidiary of the Company.

Petrofac International (UAE) LLC had EBITDA for the year ended 31 December 2012 of US$594 million, which represented 67% of the Group’s EBITDA. As of 31 December 2012, Petrofac International (UAE) LLC had net assets of US$589 million after eliminating intercompany investments and balances, which represented 38% of the Group’s net assets.

103 The purpose of Petrofac International (UAE) LLC, which is set out in its memorandum of association, is to engage in and carry on in the UAE and abroad the business of exploration, extraction, processing engineering, construction, operations, maintenance and training, transportation and distribution of oil, gas and hydrocarbon products and all related activities. Petrofac International (UAE) LLC may acquire or invest in other establishments or companies having similar objects and do all such things as may be conducive to the business of the Company, provided such activities are lawful.

There are no risks specific to Petrofac International (UAE) LLC or any encumbrances on its assets that could materially affect its ability to meet its obligations under the Guarantees, except as disclosed in “Risk Factors”.

There has been no material change in Petrofac International (UAE) LLC’s contribution to the Group’s EBITDA or net assets since 31 December 2012. As of 26 September 2013 (being the latest practicable date prior to the publication of this document), Petrofac International (UAE) LLC had no outstanding issued notes or bonds, although it is a borrower under the Revolving Credit Facility described under “Operating and Financial Review—Liquidity and Capital Resources—Indebtedness—Revolving Credit Facility”.

104 DESCRIPTION OF NOTES AND GUARANTEES

General The $750,000,000 3.400% Notes due 2018 (the “Notes”) will be issued on or about 10 October 2013 by Petrofac Limited, as issuer (the “Issuer”), and will be irrevocably and unconditionally guaranteed by Petrofac International Ltd and Petrofac International (UAE) LLC, as guarantors (the “Guarantors”), pursuant to the deeds of guarantee, each to be dated 10 October 2013 and executed by each Guarantor (the “Deeds of Guarantee”). Citibank NA, London Branch will be appointed the fiscal and paying agent and transfer agent (referred to herein as the “Paying Agent”) and Citigroup Global Markets Deutschland AG will be appointed registrar (the “Registrar”) pursuant to the Fiscal and Paying Agency Agreement to be dated on or about 10 October 2013, executed by the Paying Agent, the Registrar the Issuer and the Guarantors (the “Fiscal and Paying Agency Agreement”). The Notes will have the benefit of a deed of covenant to be dated on or about 10 October 2013 executed by the Issuer (the “Deed of Covenant”). Copies of the Fiscal and Paying Agency Agreement, the Notes, the Deeds of Guarantee and the Deed of Covenant will be available for inspection at the registered office of the Paying Agent. The holders of the Notes and the Guarantees will be deemed to have notice of, all the provisions of the Fiscal and Paying Agency Agreement. The following summaries of certain provisions of the Notes, the Guarantees, the Deed of Covenant and the Fiscal and Paying Agency Agreement do not purport to be complete and are subject to, and are qualified in their entirety by reference to, the detailed provisions of the Notes, the Guarantees, the Deed of Covenant and the Fiscal and Paying Agency Agreement. Any term used herein but not defined shall have the meaning assigned to such term in the Fiscal and Paying Agency Agreement.

Principal, Maturity and Interest The Notes are initially issuable in the aggregate principal amount of US$750 million and will mature on 10 October 2018. The Notes will bear interest at the rate of 3.400% per annum from 10 October 2013. Interest on the Notes will be payable semi-annually in arrears on 10 April and 10 October of each year commencing on 10 April 2014, to the person in whose name any Note is registered at the close of business on the preceding 1 April and 1 October, respectively. Under the terms of the Notes, principal and interest are payable in US dollars in immediately available funds. In any case where the date of payment of the principal of or interest on the Notes or the date fixed for redemption of the Notes shall be, in New York City, New York, London, England, Jersey or the place of payment of interest or principal, a Saturday, a Sunday, a legal holiday or a day on which banking institutions are authorised or obligated by law to close, then payment of principal or interest need not be made on such date at such place but may be made on the next succeeding day which is not, in New York City, New York, London, England, Jersey or the place of payment of interest or principal, a Saturday, a Sunday, a legal holiday or a day on which banking institutions are authorised or obligated by law to close, with the same force and effect as if made on the date of maturity or the date fixed for redemption or interest payment date, and no interest shall accrue for the period after such date. Interest shall be calculated on the basis of a 360-day year of twelve 30-day months. The Notes will not be entitled to the benefit of any sinking fund.

Payments of interest and principal with respect to interests in the global securities will be credited to the account of the holders of such interests with the Depository Trust Company (“DTC”), including to participants Euroclear SA/NV (“Euroclear”) and Clearstream Banking, société anonyme (“Clearstream, Luxembourg”).

Status of Notes and Guarantees The Notes will be unsecured and unsubordinated obligations of the Issuer and rank pari passu in right of payment with other unsecured and unsubordinated indebtedness of the Issuer from time to time outstanding. The Issuer is the parent company of the Group. It conducts a significant amount of business through the ownership, direct and indirect, of interests in its subsidiaries, and the right of the Issuer to participate in any distribution of assets of any of its subsidiaries upon such subsidiary’s liquidation or reorganisation or otherwise is subject to the prior claims of creditors of that subsidiary, except to the extent that the Issuer may itself be recognised as a creditor of that subsidiary. Accordingly, the Issuer’s obligations under the Notes will be effectively subordinated to all existing and future liabilities of its respective subsidiaries (except the Guarantors). As of 31 August 2013, the Issuer’s subsidiaries (other than the Guarantors) had interest bearing loans and borrowings of US$174 million, of which US$148 million related to the senior secured BFPL Facility, which is non-recourse to the rest of the Group. In addition, Petrofac International (UAE) LLC is a borrower, and each of the Issuer and Petrofac International Ltd has fully and unconditionally guaranteed borrowings, under our Revolving Credit Facility. See “Business—Description of the Business—Organisational Structure” and “Operating and Financial Review—Indebtedness—Revolving Credit Facility.”

105 The Guarantors will irrevocably and unconditionally guarantee, on a joint and several basis, the due and punctual payment (and not collectability) of the principal of and interest on the Notes (including the payment of any Additional Amounts described under “—Additional Amounts”) when and as the same shall become due and payable by the Issuer, whether at stated maturity, by declaration of acceleration, call for redemption or otherwise. The Guarantees will be an unsecured obligation of the Guarantors and will rank pari passu in right of payment with other unsecured and unsubordinated indebtedness of the Guarantors from time to time outstanding. The Guarantees will be limited to the maximum amount that would not render the Guarantors’ obligations subject to avoidance under applicable fraudulent conveyance, corporate benefit, financial assistance or other applicable laws. By virtue of this limitation, the Guarantors’ obligations under the Guarantees could be significantly less than amounts payable with respect to the Notes. See “Risk Factors—Risks Relating to the Notes—Corporate benefit and financial assistance laws and other limitations on the Guarantees may adversely affect the validity and enforceability of the Guarantees”.

Form and Denomination The Notes will be issued in fully registered form, without interest coupons attached, in the form of one or more global notes (each, a “Global Note”) and will each have the benefit of a Deed of Covenant. Notes represented by one or more Global Notes will be offered and sold in minimum denominations of US$2,000 or any amount in excess thereof which is a multiple of US$1,000. Definitive notes issued in exchange for beneficial interests in the Global Notes in the form of permanent serialised Notes in registered form (each, a “Definitive Note”) may, in the limited circumstances specified by the terms of the Global Notes, be issued to each holder of Notes in respect of its registered holding or holdings of Notes. See “Book-Entry System; Delivery and Form” for more information about the form of the Notes and their clearance and settlement.

Additional Mechanics Payment and Paying Agent The Issuer or any Guarantor will pay interest, principal and any other money due on the Notes and any redemption price to the Paying Agent. On the respective payment date of such payments, the Paying Agent will make such payments to DTC or its nominee, as the case may be, in accordance with arrangements between any paying agent and the DTC or its nominee.

For so long as the Notes are outstanding, the Issuer will maintain a paying agent (which may be the Paying Agent) in a jurisdiction not required to withhold or deduct tax pursuant to the European Union Directive 2003/48/EC or any other Directive implementing the conclusions of the ECOFIN Council meeting of 26-27 November 2000, or any law implementing or complying with, or introduced in order to conform to, such Directive.

Beneficial holders of the Notes whose Notes are held of record by a broker, dealer, commercial bank, trust company or other nominee and other indirect holders should consult their banks or brokers for information on how they will receive payments.

Notices The Issuer and the Paying Agent will send notices only to registered holders, using their addresses as listed in the notes register.

All money that the Issuer or any Guarantor pays to a paying agent that remains unclaimed at the end of two years after the amount is due to direct holders will be repaid to the Issuer or such Guarantor, as applicable. After that two-year period, the direct holder may look only to the Issuer or such Guarantor, or their respective successors, for payment and not to the Paying Agent or anyone else.

Certain Definitions Set forth below are certain definitions applicable to this “Description of Notes and Guarantees”.

“Attributable Indebtedness” means, as to any particular lease under which any Person is liable at the time as lessee, and at any date as of which the amount of the payment is to be determined, the total net amount of rent required to be paid by such Person under such lease during the remaining term of such lease (including any

106 period for which such lease has been extended or may, at the option of the lessor, be extended), discounted from the respective due dates thereof to the date of determination at a rate per annum equivalent to the rate inherent in such lease (as determined by the directors of the Issuer) compounded semi-annually, excluding amounts required to be paid on account of or attributable to operating costs and overhead charges and including, in certain circumstances, any termination penalty in the case of a lease terminable by the lessee.

“Below Investment Grade Ratings Event” means the Notes cease to be rated Investment Grade by at least two of the three Rating Agencies on any date during the period commencing 60 days prior to, and ending 60 days after (which 60-day period will be extended so long as the rating of the notes is under publicly announced consideration for a possible downgrade by any Rating Agency) the earlier of (1) the occurrence of a Change of Control or (2) public notice of the occurrence of a Change of Control or the intention of the Issuer to effect a Change of Control. Notwithstanding the foregoing, a Below Investment Grade Ratings Event otherwise arising by virtue of a particular reduction in rating shall not be deemed to have occurred in respect of a particular Change of Control (and thus shall not be deemed a Below Investment Grade Ratings Event for purposes of the definition of Change of Control Repurchase Event hereunder) if the Rating Agencies making the reduction in rating to which this definition would otherwise apply do not announce or do not publicly confirm or inform the Paying Agent in writing at its request that the reduction was the result, in whole or in part, of any event or circumstance comprised of or arising as a result of, or in respect of, the applicable Change of Control (whether or not the applicable Change of Control shall have occurred at the time of the ratings event).

“Business Day” means any day which is not, in London, England, New York City, New York, Jersey, or the place of payment of interest or principal a Saturday, Sunday, a legal holiday or a day on which banking institutions in such places are authorised or obligated by law to close.

“Change of Control” means the occurrence of one or more of the following: 1. the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of consolidation, amalgamation or merger), in one or a series of related transactions, of all or substantially all of the assets of the Issuer and its Subsidiaries taken as a whole to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act), other than to the Issuer or one of its Subsidiaries; 2. the consummation of any transaction (including, without limitation, any consolidation, amalgamation, or merger or other combination (including by way of a scheme of arrangement)) the result of which is that any “person” (as that term is used in Section 13(d)(3) of the Exchange Act) becomes the beneficial owner (as defined in Rules 13d-3 and 13d-5 under the Exchange Act), directly or indirectly, of more than 50% of the outstanding Voting Stock of the Issuer, measured by voting power rather than number of shares; 3. the Issuer consolidates with, or merges with or into, any Person, or any Person consolidates with, or merges with or into, the Issuer, in any such event pursuant to a transaction in which any of the outstanding Voting Stock of the Issuer or such other Person is converted into or exchanged for cash, securities or other property, other than any such transaction where the shares of the Voting Stock of the Issuer outstanding immediately prior to such transaction constitute, or are converted into or exchanged for, a majority of the Voting Stock of the surviving Person immediately after giving effect to such transaction; 4. the first day on which the majority of the members of the board of directors of the Issuer cease to be Continuing Directors; or 5. the adoption of a plan relating to the liquidation, winding up or dissolution of the Issuer.

Notwithstanding the foregoing, a transaction will not be deemed to involve a change of control for the purposes of this definition only if (1) the Issuer becomes a direct or indirect wholly owned subsidiary of a holding company and (2)(A) the direct or indirect holders of the Voting Stock of such holding company immediately following that transaction are substantially the same as the holders of the Issuer’s Voting Stock immediately prior to that transaction or (B) immediately following that transaction no Person (other than a holding company satisfying the requirements of this sentence) is the beneficial owner, directly or indirectly, of more than 50% of the Voting Stock of such holding company.

“Change of Control Repurchase Event” means the occurrence of both a Change of Control and a Below Investment Grade Ratings Event.

“Comparable Treasury Issue” means the United States Treasury security selected by an Independent Investment Banker as having an actual or interpolated maturity comparable to the remaining term of the Notes

107 that would be utilised, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of a comparable maturity to the remaining term of the Notes.

“Comparable Treasury Price” means (i) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest Reference Treasury Dealer Quotations, or (ii) if the Independent Investment Banker obtains fewer than four such Reference Treasury Dealer Quotations, the average of all such quotations.

“Consolidated Net Tangible Assets” means the aggregate amount of assets (less applicable provisions) after deducting therefrom (1) all current liabilities; (2) all goodwill, trade names, trademarks, patents, unamortised debt discount and financings costs and all similar intangible assets; and (3) appropriate adjustments on account of minority interests of other Persons holding stock in any Subsidiary of the Issuer, all as set forth on the most recent consolidated balance sheet of the Issuer and computed in accordance with IFRS.

“Continuing Director” means, as of any date of determination, any member of the board of directors of the Issuer who: • was a member of such board of directors on the date of the Fiscal and Paying Agency Agreement; or • was nominated for election or elected to such board of directors with the approval of a majority of the Continuing Directors who were members of such board of directors at the time of such nomination or election.

“EPC Facility” means any building, structure, manufacturing or processing facility, engineering centre, plant, ship, offshore platform, onshore complex, subsea structure, dam or other facility (a) in which the Issuer or any Subsidiary has a temporary ownership interest and (b) that is purchased or constructed pursuant to contractual arrangements under which ownership or possession will be transferred to a counterparty (other than a Subsidiary) or a third party upon completion of any phase or the entirety of such EPC Facility.

“Guarantor Jurisdiction” shall mean each jurisdiction in which any Guarantor or any successor thereof is organised or resident for tax purposes, or any political subdivision or taxing authority thereof or therein.

“IFRS” means International Financial Reporting Standards as issued by the International Accounting Standards Board.

“Indebtedness” means all obligations for borrowed money represented by notes, bonds, debentures or similar evidence of indebtedness and obligations for borrowed money evidenced by credit, loan or other like agreements.

“Independent Investment Banker” means any Reference Treasury Dealer (as defined below) selected by the Issuer.

“Investment Grade” means a rating of Baa3 or better by Moody’s (or its equivalent under any successor rating categories of Moody’s); a rating of BBB- or better by S&P (or its equivalent under any successor rating categories of S&P); or the equivalent Investment Grade credit rating from any additional Rating Agency or Rating Agencies selected by the Issuer.

“Issuer Jurisdiction” shall mean each jurisdiction in which the Issuer or any successor thereof is organised or resident for tax purposes, or any political subdivision or taxing authority thereof or therein.

“Limited Recourse Indebtedness” means any Project Financing or other Indebtedness incurred by the Issuer or any Subsidiary from any lender whose rights on enforcement in connection with such Indebtedness do not extend generally to the assets of the relevant borrower (unless it is a single purpose vehicle) or to the Issuer or any Restricted Subsidiary or their respective assets (other than interests in the shares of the relevant borrower if it is a single purpose vehicle), but whose rights are limited by reference to the assets relating to the matter in respect of which such Indebtedness was incurred, provided that any assurance given by the Issuer or any Subsidiary that the relevant borrower shall have available to it sufficient management and technical resources to enable it to undertake the project, contract or business in question shall not exclude such Indebtedness from this definition.

“Moody’s” means Moody’s Investors Service Ltd.

“Mortgage” means any mortgage, deed of trust, pledge, hypothec, lien, encumbrance, charge or other security interest of any kind.

108 “Person” means any individual, corporation, partnership, joint venture, association, limited liability company, joint stock company, trust, unincorporated organisation or government or any agency or political subdivision thereof.

“Principal Property” means the ownership interest of the Issuer or any Subsidiary in any building, structure, manufacturing or processing facilities, engineering centre, plant, ship, offshore platform, onshore complex, subsea structure, dam or other facility (other than in connection with an EPC Facility) together with the land upon which it is erected (which shall not include any sub-surface assets, including but not limited to rights to reserves or production of oil, gas or any other hydrocarbon resources) and fixtures comprising a part thereof, whether owned as of the date of the Fiscal and Paying Agency Agreement or thereafter acquired or constructed by the Issuer or any Subsidiary, of which interest the net book value in each case, on the date as of which the determination is being made, is an amount which exceeds 10% of Consolidated Net Tangible Assets, other than (i) any such building, structure, manufacturing or processing facilities, engineering centre, plant, ship, offshore platform, onshore complex, subsea structure, dam or other facility which, in the opinion of the board of directors of the Issuer, acting in good faith, is not of material importance to the total business conducted by the Issuer and its Subsidiaries as an entirety or (ii) any portion of any such property which, in the opinion of the board of directors of the Issuer, acting in good faith, is not of material importance to the use or operation of such property.

“Project Financing” means the financing or refinancing of the acquisition, construction, expansion, improvement or development of any physical assets in which the providers of such finance or refinance solely look to the entity that owns and operates such assets, the equity interests in such entity, the assets themselves and/or the revenues generated thereby as the source of repayment of the amounts financed or refinanced, without recourse to the Issuer or any Subsidiary (other than such entity) other than through a completion guarantee or other obligations that are customary in non-recourse financing or refinancing.

“Rating Agency” means each of Moody’s and S&P; provided that if any of Moody’s or S&P ceases to rate the Notes or fails to make a rating of the Notes publicly available for reasons outside of the Issuer’s or the Guarantors’ control, a “nationally recognised statistical rating organisation” within the meaning of Section 3(a)(62) of the Exchange Act, selected by the Issuer (as certified by a resolution of the Group’s Chief Executive or Chief Financial Officer) as a replacement agency for Moody’s or S&P, or all of them, as the case may be.

“Reference Treasury Dealer” means each of Barclays Capital Inc. and J.P. Morgan Securities LLC, and their respective successors, provided, however, that if any of the foregoing shall cease to be a primary US Government securities dealer in New York City, New York (a “Primary Treasury Dealer”), the Issuer shall substitute therefor any Primary Treasury Dealer.

“Reference Treasury Dealer Quotations” means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the Independent Investment Banker, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the Independent Investment Banker at 5:00 p.m., New York City time, on the third Business Day preceding such redemption date.

“Restricted Subsidiary” means (1) any Subsidiary which owns or leases a Principal Property; and (2) any Subsidiary engaged primarily in the business of owning or holding securities of Restricted Subsidiaries.

“S&P” means Standard & Poor’s Financial Services LLC, a division of the McGraw-Hill Companies Inc.

“Sale and Leaseback Transactions” mean any arrangement with a bank, insurance company or other lender or investor (other than the Issuer or a Restricted Subsidiary) providing for the leasing by the Issuer or any Restricted Subsidiary of any Principal Property which has been or is to be sold or transferred, more than 180 days after the later of the acquisition, completion of construction or commencement of full operation thereof by the Issuer or such Restricted Subsidiary to such lender or investor or to any Person to whom funds have been or are to be advanced by such lender or investor on the security of that property or asset.

“Significant Subsidiary” means as of the date hereof each of Petrofac Energy Development Sdn Bhd, Petrofac International Ltd, Petrofac International (UAE) LLC and Petrofac (Malaysia-PM 304) Limited and at any time henceforth any Subsidiary that would be a “significant subsidiary” under the definition in Article 1, Rule 1-02(w)(2) of Regulation S-X (but as calculated pursuant to IFRS), promulgated pursuant to the Securities Act, as such Regulation is in effect on the date hereof.

109 “Subsidiary” means, at any relevant time, any person of which the voting shares or other interests carrying more than 50% of the outstanding voting rights attached to all outstanding voting shares or other interests are owned, directly or indirectly, by or for the Issuer and/or one or more Subsidiaries of the Issuer.

“Treasury Rate” means, with respect to any redemption date, the rate per annum equal to the semi-annual equivalent yield to maturity (computed as at the third Business Day immediately preceding that redemption date) or interpolated (on a day count basis) of the Comparable Treasury Issue, assuming a price of the Comparable Treasury Issue (expressed as a percentage of its principal amount equal) to the Comparable Treasury Price for such redemption date.

“Voting Stock” of any specified “person” (as that term is used in Section 13(d)(3) of the Exchange Act) as of any date means the capital stock of such Person that is at the time entitled to vote generally in the election of the board of directors of such Person.

Additional Amounts All payments of, or in respect of, principal, interest and any premium made by the Issuer or any Guarantor in respect of any Note and under the Guarantees will be made without withholding or deduction for, or on account of, any present or future taxes, duties, assessments or governmental charges of whatever nature (including penalties, interest and additions to tax applicable thereto) (“Taxes”) imposed or levied by or on behalf of an Issuer Jurisdiction or a Guarantor Jurisdiction, as the case may be, or any jurisdiction through which payment is made (together with the Issuer Jurisdiction and each Guarantor Jurisdiction, each a “Relevant Taxing Jurisdiction”), unless such withholding or deduction for such Taxes is required by law or by the official interpretation or administration thereof. If any withholding or deduction for Taxes of a Relevant Taxing Jurisdiction is at any time required to be made from any amounts to be paid by the Issuer or any Guarantor on or in respect of the Notes or Guarantees, the Issuer or such Guarantor will pay to a holder of a Note such additional amounts (“Additional Amounts”) as will result in receipt by the holder of such amounts as would have been received by the holder had no such withholding or deduction been required; provided, however, that neither the Issuer nor the Guarantors shall be required to make any payment of Additional Amounts for or on account of: (i) any Tax that would not have been imposed but for the existence of a present or former connection between such holder (or between a fiduciary, settlor, beneficiary, member or shareholder of such holder, if such holder is an estate, trust, partnership or corporation) and the Relevant Taxing Jurisdiction (including, without limitation, such holder (or such fiduciary, settlor, beneficiary, member or shareholder) being or having been a domiciliary, national or resident thereof or being or having been present or engaged in trade or business therein or having or having had a permanent establishment therein) other than the mere holding or ownership of a Note or the collection of principal of or interest and premium, if any, on, or the enforcement of, a Note; (ii) any Tax that would not have been imposed but for the presentation of the Note (where presentation is required) for payment on a date more than 30 days after the date on which such payment became due and payable or the date on which payment thereof is duly provided for, whichever occurs later, except to the extent that the holder would have been entitled to such Additional Amounts if it had presented the Note for payment on any day within such period of 30 days; (iii) any estate, inheritance, gift, sales, transfer, personal property or similar tax, duty, assessment or other governmental charge; (iv) any Tax that is payable otherwise than by withholding or deduction from payments on (or in respect of) the Notes; (v) any Tax that is imposed or levied by reason of, or any amount required to be withheld or deducted for or on account of Tax as a result of, the failure by the holder or the beneficial owner of the Note to comply in a timely manner with a request by or on behalf of the Issuer or any Guarantor (A) to provide information concerning the nationality, residence, or identity of the holder or such beneficial owner or (B) to make any declaration or other similar claim to satisfy any information or reporting requirement, which in the case of (A) or (B), is required or imposed by the applicable law of the Relevant Taxing Jurisdiction as a precondition to exemption from all or part of such Tax; (vi) any Tax required to be withheld or deducted by any paying agent from any payment on a Note if such payment could be made without such withholding or deduction by presenting the Note (where presentation is required) to any other paying agent;

110 (vii) any withholding or deduction that is required to be made pursuant to sections 1471 through 1474 of the US Internal Revenue Code of 1986, as amended, any regulations thereunder, any official interpretations thereof, any agreement entered into thereunder, and any law implementing an intergovernmental agreement or approach thereto; (viii) any withholding or deduction that is required to be made pursuant to European Union Directive 2003/48/EC or any other Directive on the taxation of savings implementing the conclusions of the ECOFIN Council meeting of November 26-27, 2000, or any law implementing or complying with, or introduced in order to conform to, such Directive; or (ix) any combination of the items above.

In addition, no Additional Amounts will be paid with respect to any payment of principal of, and any premium or interest on, any Note to any holder that is a fiduciary, partnership, limited liability company or person other than the sole beneficial owner of such payment to the extent such payment would be required by the laws of the Relevant Taxing Jurisdiction, to be included for tax purposes in the income of a beneficiary or settlor with respect to such fiduciary, a member of such partnership, an interest holder in a limited liability company or a beneficial owner who would not have been entitled to such Additional Amounts had it been the holder of such Note.

Wherever there is mentioned in any context the payment of principal of, and any premium or interest on, any Note, such mention will be deemed to include payment of Additional Amounts provided for in the Notes to the extent that in such context, Additional Amounts are, were or could be payable in respect thereof.

Optional Redemption The Issuer or any Guarantor may redeem the Notes, in whole or in part, at the option of the Issuer or such Guarantor at any time and upon notice as described below, at a redemption price equal to the greater of (i) 100% of the principal amount of the Notes to be redeemed and (ii) the sum of the present values of the remaining scheduled payments of principal and interest thereon (excluding any portion of such payments of interest accrued as of the date of redemption) discounted to the date of redemption on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate plus 35 basis points, plus in each case accrued and unpaid interest to the date of redemption.

Notice of redemption of the Notes, as provided above, shall be given not less than 30 nor more than 60 days prior to the date fixed for redemption, as provided in the Fiscal and Paying Agency Agreement. Notice having been given, the Notes to be redeemed shall become due and payable on the date fixed for redemption and will be paid at the redemption price, together with accrued interest to the date fixed for redemption, at the place or places of payment and in the manner specified in the Notes.

From and after the redemption date, if moneys for the redemption of the Notes shall have been available as provided in the Notes to be redeemed on the redemption date, the Notes shall cease to bear interest, and the only right of the holders of the Notes shall be to receive payment of the redemption price and all unpaid interest accrued to the date of redemption.

Optional Tax Redemption The Notes may be redeemed at the option of the Issuer, as a whole but not in part, upon notice as described below, at a redemption price equal to 100% of the principal amount thereof, together with any accrued and unpaid interest to the date fixed for redemption, if as a result of the occurrence of any change in, or amendment to, the laws (or any regulations or rulings promulgated thereunder) of a Relevant Taxing Jurisdiction, or any change in official position regarding the application or interpretation of such laws, regulations or rulings (including a holding by a court of competent jurisdiction or administrative interpretation), which change or amendment is announced and becomes effective on or after the date of this Offering Memorandum, on the occasion of the next payment of principal or interest in respect of the Notes, the Issuer or any Guarantor, as the case may be, would be obligated to pay Additional Amounts as described under “—Additional Amounts” above and such obligation cannot be avoided by the Issuer or such Guarantor taking reasonable measures available to it (including, for example, appointing a paying agent in another jurisdiction). Prior to the giving of any notice of redemption of the Notes pursuant to the foregoing, the Issuer shall deliver to the Paying Agent an opinion of independent legal counsel or an independent accountant (of recognised standing) addressed to the Issuer or such

111 Guarantor stating that the Issuer or such Guarantor, as the case may be, would be required to pay such Additional Amounts as a result of such a change or amendment, together with a certificate from the Issuer setting forth a statement of facts showing that the conditions precedent to the right of the Issuer to so redeem have occurred.

In the event that obligations of the Issuer or any Guarantor under the Notes are assumed pursuant to the terms and conditions of the Notes by any corporation organised under the laws of a jurisdiction other than a jurisdiction that is a Relevant Taxing Jurisdiction immediately prior to such assumption, such successor corporation shall be entitled to redeem the Notes subject to the terms of the preceding paragraph, substituting the date of such assumption for the date of this Offering Memorandum.

Notice of redemption of the Notes as provided above shall be given, not less than 30 nor more than 60 days prior to the date fixed for redemption; provided that no such notice of redemption shall be given earlier than 90 days prior to the earliest date on which the Issuer or the relevant Guarantor would be required to pay Additional Amounts if a payment in respect of such Notes was then due, all as provided in the Fiscal and Paying Agency Agreement. Notice having been given, the Notes shall become due and payable on the date fixed for redemption and will be paid at the redemption price, together with accrued and unpaid interest to the date fixed for redemption, at the place or places of payment and in the manner specified in such Notes.

Any Notes that are redeemed will be cancelled.

Change of Control Repurchase Event If a Change of Control Repurchase Event occurs, unless the Issuer has exercised its right to redeem the Notes as described above, the Issuer or any Guarantor will be required to make an offer to each holder of Notes to repurchase all or any part (equal to US$2,000 or an integral multiple of US$1,000 in excess thereof) of that holder’s Notes at a repurchase price in cash equal to 101% of the aggregate principal amount of Notes repurchased plus any accrued and unpaid interest on the Notes repurchased to, but not including, the date of repurchase.

Within 30 days following any Change of Control Repurchase Event or, at the option of the Issuer or any Guarantor, prior to any Change of Control, but after the public announcement of the Change of Control, the Issuer or such Guarantor will mail, by first class mail or equivalent, a notice to each holder, with a copy to the Paying Agent, describing the transaction or transactions that constitute or may constitute the Change of Control Repurchase Event and offering to repurchase the Notes on the payment date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed. The notice shall, if mailed prior to the date of consummation of the Change of Control, state that the offer to purchase is conditional upon a Change of Control Repurchase Event occurring on or prior to the payment date specified in the notice.

The Issuer and the Guarantors will comply with the requirements of the US Securities Exchange Act of 1934, as amended (the “Exchange Act”), and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the Notes as a result of a Change of Control Repurchase Event. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control Repurchase Event provisions of the Notes, the Issuer and the Guarantors will comply with the applicable securities laws and regulations and will not be deemed to have breached their respective obligations under the Change of Control Repurchase Event provisions of the Notes by virtue of such conflict.

On the repurchase date following a Change of Control Repurchase Event, the Issuer or any Guarantor will, to the extent lawful: • accept for payment all Notes or portions of Notes properly tendered pursuant to the Issuer’s or such Guarantor’s offer; • deposit an amount equal to the aggregate purchase price and accrued interest in respect of all Notes or portions of Notes properly tendered with the Paying Agent (or with such other agent as agreed upon at such time); and • deliver or cause to be delivered to the Paying Agent the Notes properly accepted, together with an officers’ certificate stating the aggregate principal amount of Notes being purchased by the Issuer or such Guarantor.

The Paying Agent will promptly mail to each holder of Notes properly tendered the purchase price for the Notes, and the Paying Agent will promptly authenticate and mail (or cause to be transferred by book-entry) to each holder a new note equal in principal amount to any un-purchased portion of any Notes surrendered; provided that each new note will be in a principal amount of US$2,000 or an integral multiple of US$1,000 in excess thereof.

112 The Issuer or the Guarantors will not be required to make an offer to repurchase the Notes upon a Change of Control Repurchase Event if a third party makes such an offer in the manner, at the times and otherwise in compliance with the requirement for an offer made by the Issuer or any Guarantor and such third party purchases all Notes properly tendered and not withdrawn under its offer.

The Change of Control Repurchase Event feature of the Notes may in certain circumstances make more difficult or discourage a sale or takeover of the Issuer and, thus, the removal of incumbent management. Subject to the limitations discussed below, the Issuer or any Guarantor could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalisations, that would not constitute a Change of Control under the Notes, but that could increase the amount of debt outstanding at such time or otherwise affect the Issuer’s or such Guarantor’s capital structure or credit ratings on the Notes.

The Issuer or the Guarantors may not have sufficient funds to repurchase all the Notes, or any other outstanding debt securities that the Issuer or the Guarantors would be required to repurchase, upon a Change of Control Repurchase Event.

Covenants of the Issuer and the Guarantors Limitation on Mergers and Consolidations Under the Notes, each of the Issuer and the Guarantors may not consolidate or amalgamate with or merge (including by way of a scheme of arrangement) into or with any other Person, or, directly or indirectly, sell, convey, transfer or lease its properties and assets as an entirety or substantially as an entirety to any Person (other than a Person satisfying the condition set forth in clause (i), below, that is directly or indirectly wholly owned by the Issuer), unless: (i) the Person formed by or continuing from such consolidation or amalgamation or into which the Issuer or any Guarantor is merged or the Person which acquires or leases the Issuer’s or any Guarantor’s properties and assets as an entirety or substantially as an entirety is organised and existing under the laws of, the United Kingdom, the United States, or any other country that is a member of the Organisation for Economic Cooperation and Development, or Jersey, Hong Kong, Singapore or the United Arab Emirates; (ii) the successor Person assumes the Issuer’s or such Guarantor’s obligations, as the case may be, under the Notes, the Guarantees and the Fiscal and Paying Agency Agreement to pay Additional Amounts; (iii) if the Issuer or such Guarantor, as applicable, is not the continuing entity, the successor Person assumes all of the Issuer’s or such Guarantor’s obligations under the Notes, the Guarantees, the Deed of Covenant and under the Fiscal and Paying Agency Agreement; (iv) immediately before and after giving effect to such transaction, no Event of Default (as defined below) and no event which, after notice or lapse of time or both, would become an Event of Default, will have happened and be continuing; and (v) certain other conditions are met.

If, as a result of any such transaction, any of the Issuer’s or any of such Guarantor’s Principal Properties become subject to a Mortgage, then, unless such Mortgage could be created pursuant to the Fiscal and Paying Agency Agreement provisions described under the section headed “—Negative Pledge” without equally and ratably securing the Notes, the Issuer or such Guarantor, simultaneously with or prior to such transaction, will cause the Notes to be secured equally and ratably with or prior to the Indebtedness secured by such Mortgage.

The Notes will not contain covenants or other provisions to afford protection to holders of the Notes in the event of a highly leveraged transaction or a change in control of the Issuer or the Guarantor except as provided therein.

Upon certain mergers or consolidations involving the Issuer or any Guarantor, or upon certain sales or conveyances of the respective properties of the Issuer or any Guarantor as an entirety or substantially as an entirety, the obligations of the Issuer or such Guarantor, as the case may be, under the Notes or the Guarantees, as the case may be, shall be assumed by the Person formed by such merger or consolidation or which shall have acquired such property (except in the case of an acquisition of such property, for any such Person that meets the condition set forth in clause (i), above, that is directly or indirectly wholly owned by the Issuer) and upon such assumptions such Person shall succeed to and be substituted for the Issuer or such Guarantor, as the case may be, and then the Issuer or such Guarantor, as the case may be, will be relieved from all obligations under the Notes,

113 the Guarantees, the Deed of Covenant or the Fiscal Paying Agency Agreement, as the case may be. The terms “Issuer” and “Guarantor”, as used in the Notes, the Guarantees, the Deed of Covenant and the Fiscal Paying Agency Agreement also refer to any such successors or assigns so substituted.

Negative Pledge The Notes provide that, for so long as any of the Notes remain outstanding, the Issuer and each Guarantor will not, and the Issuer will not permit any Restricted Subsidiary to, create, permit to exist, incur, issue, guarantee, assume or otherwise have outstanding any Mortgage on or over any Principal Property now owned or subsequently owned by the Issuer or a Restricted Subsidiary to secure any Indebtedness of the Issuer, any Guarantor or any Restricted Subsidiary, or on shares of stock or Indebtedness of any Restricted Subsidiary now owned or subsequently owned by the Issuer or a Restricted Subsidiary to secure any Indebtedness of the Issuer, any Guarantor or any Restricted Subsidiary, unless at the time thereof or prior thereto the Notes then outstanding are secured equally and ratably with (or prior to) any and all such Indebtedness for so long as such Indebtedness is so secured by such Mortgage; provided, however, such negative pledge will not apply to or operate to prevent or restrict the following permitted encumbrances: 1. any Mortgage on property, shares of stock or Indebtedness of any Person existing at the time such Person becomes a Restricted Subsidiary or created, incurred, issued or assumed in connection with the acquisition of any such Person; 2. any Mortgage on any Principal Property created, incurred, issued or assumed at or prior to the time such property became a Principal Property or existing at the time of acquisition of such Principal Property by the Issuer or a Restricted Subsidiary, whether or not assumed by the Issuer or such Restricted Subsidiary; provided that no such Mortgage will extend to any other Principal Property of the Issuer or any Restricted Subsidiary; 3. any Mortgage on all or any part of any Principal Property (including any improvements or additions to improvements on a Principal Property) hereafter acquired, developed, expanded or constructed by the Issuer or any Restricted Subsidiary to secure the payment of all or any part of the purchase price, cost of acquisition or cost of development, expansion or construction of such Principal Property or of improvements or additions to improvements thereon (or to secure any Indebtedness incurred by the Issuer or a Restricted Subsidiary for the purpose of financing all or any part of the purchase price, cost of acquisition or cost of development, expansion or construction thereof or of improvements or additions to improvements thereon) created prior to, at the time of, or within 360 days after the later of, the acquisition, development, expansion or completion of construction (including construction of improvements or additions to improvements thereon), or commencement of full operation of such Principal Property; provided that no such Mortgage will extend to any other Principal Property of the Issuer or a Restricted Subsidiary other than, in the case of any such construction, improvement, development, expansion or addition to improvement, all or any part of any other Principal Property on which the Principal Property so constructed, developed or expanded, or the improvement or addition to improvement, is located; 4. any Mortgage on any Principal Property of any Restricted Subsidiary to secure Indebtedness owing by it to the Issuer, any Guarantor or another Restricted Subsidiary; 5. any Mortgage on any Principal Property of the Issuer to secure Indebtedness owing by it to any Guarantor or another Restricted Subsidiary; 6. any Mortgage on any Principal Property or other assets of the Issuer or any Restricted Subsidiary existing on the original issue date of the Notes; 7. any Mortgage on any Principal Property arising by operation of law (or an agreement solely evidencing otherwise applicable law) and (i) arising in the ordinary course of business or (ii) not securing amounts more than 90 days overdue or otherwise being contested in good faith; 8. judgment Mortgages on any Principal Property not giving rise to an Event of Default; 9. any Mortgage on any Principal Property of the Issuer or any Restricted Subsidiary in favour of the government of any country or political subdivision thereof, or any instrumentality of any of them, securing the obligations of the Issuer or any Restricted Subsidiary pursuant to any contract or payments owed to such entity pursuant to applicable laws, rules, regulations or statutes; 10. any Mortgage on or over all or any part of the interest of the Issuer or any Restricted Subsidiary in any joint venture, partnership or similar undertaking, including the revenues and assets derived by the Issuer or any Restricted Subsidiary from such joint venture, partnership or similar undertaking, or employed by the Issuer

114 or any Restricted Subsidiary in such joint venture, partnership or similar undertaking, which is in favour of its co-venturers and/or the manager or operator of the joint venture, partnership or similar undertaking as security for the due payment of amounts payable under or in respect of such joint venture, partnership or similar undertaking; 11. Mortgages arising in connection with any Limited Recourse Indebtedness; 12. any Mortgage on any Principal Property or other assets of the Issuer or any Restricted Subsidiary created for the sole purpose of extending, renewing, altering or refunding any of the foregoing Mortgages (or any successive extension, renewal, alteration or refunding thereof), provided that the Indebtedness secured thereby will not exceed the principal amount of Indebtedness so secured at the time of such extension, renewal, alteration or refunding, plus an amount necessary to pay fees and expenses, including premiums, related to such extensions, renewals, alterations or refundings, and that such extension, renewal, alteration or refunding Mortgage will be limited to all or any part of the same Principal Property and improvements and additions to improvements thereon and/or shares of stock and Indebtedness of a Restricted Subsidiary which secured the Mortgage extended, renewed, altered or refunded either of such property or shares of stock or Indebtedness; 13. Mortgages on any Principal Property subject to Sale and Leaseback Transactions described below in clause (1), (3) or (4) of the section headed “—Limitation on Sale and Leaseback Transactions”; 14. any Mortgage arising under any retention of title, hire purchase or conditional sale arrangement or arrangements having similar effect in respect of goods supplied to the Issuer or any Restricted Subsidiary in the ordinary course of trading and on the supplier’s standard or usual terms and not arising as a result of any default or omission by the Issuer or any Restricted Subsidiary; or 15. any Mortgage on any Principal Property or on any shares of stock or Indebtedness of any Restricted Subsidiary created, incurred, issued or assumed to secure Indebtedness of the Issuer or any Restricted Subsidiary, which would otherwise be subject to the foregoing restrictions, in an aggregate amount which, together with the aggregate principal amount of other Indebtedness secured by Mortgages on any Principal Property or on any shares of stock or Indebtedness of any Restricted Subsidiary then outstanding (excluding Indebtedness secured by Mortgages permitted under the foregoing exceptions) and the Attributable Indebtedness in respect of all Sale and Leaseback Transactions entered into after the date of the Fiscal and Paying Agency Agreement (not including Attributable Indebtedness in respect of any such Sale and Leaseback Transactions described below in clause (1), (3) or (4) of the section headed “—Limitation on Sale and Leaseback Transactions”) would not then exceed 20% of Consolidated Net Tangible Assets of the Issuer.

Limitation on Sale and Leaseback Transactions The Notes provide that, for so long as any of the Notes remain outstanding, and subject to the provisions of the Notes, the Issuer or any Guarantor will not, and the Issuer will not permit any Restricted Subsidiary to, enter into any Sale and Leaseback Transaction unless: (1) such transaction involves a lease or right to possession or use for a temporary period not to exceed three years following such transaction, by the end of which it is intended that the use of such property by the lessee will be discontinued; (2) immediately prior to the entering into of such transaction, the Issuer or such Restricted Subsidiary could create a Mortgage on Principal Property subject to the Sale and Leaseback Transaction securing Indebtedness in an amount equal to the Attributable Indebtedness with respect to the particular Sale and Leaseback Transaction; (3) the proceeds of such transaction within 180 days after such transaction, are applied to either (A) the payment of all or any part of the purchase price, cost of acquisition, cost of development, cost of expansion or cost of construction of a Principal Property or cost of improvements or additions to improvements thereon or (B) the retirement of long-term debt ranking at least ratably with the Notes or (4) such transaction is in respect of an offshore installation, vessel or similar asset constructed or purchased by the Issuer or any Restricted Subsidiary, including through any consortium or joint venture arrangement.

Information For so long as the Issuer is not required to file information with the US Securities and Exchange Commission pursuant to Section 13 or 15(d) of the Exchange Act: 1. The Issuer will make available on its website (a) audited annual consolidated financial statements audited by an internationally recognised independent public accountant with respect to such year within 120 days of the end of such year, and (b) for the first six months of each year, unaudited condensed consolidated interim

115 financial statements within 90 days of the end of each such period, in each case, prepared in accordance with IFRS or other generally accepted accounting principles as in effect at the date of the relevant statements, together with a discussion by management of the results for the relevant period. 2. The Issuer will make available, upon request, to any holder of Notes and any prospective purchaser of Notes, the information required pursuant to Rule 144A(d)(4) under the Securities Act.

Discharge and Defeasance The Issuer or any Guarantor may discharge its obligations to comply with any payment or other obligation on the Notes by depositing funds or obligations issued by the United States in an amount sufficient to provide for the timely payment of principal, interest and all other amounts due under the Notes with the Paying Agent, acting as banker for such purposes; provided that the Issuer or such Guarantor has received an opinion of US counsel of recognised standing with respect to US federal income tax matters to the effect that beneficial owners of the Notes will not recognise income, gain or loss for US federal income tax purposes as a result of such defeasance and will be subject to US federal income tax on the same amount and in the same manner and at the same time as would have been the case if such defeasance had not occurred, and such opinion is based on a change of law occurring after the date of this Offering Memorandum.

Events of Default The following will be Events of Default (each an “Event of Default”) with respect to the Notes: (i) the Issuer or any Guarantor shall default in payment or prepayment of all or any part of the principal of any Note or any premium or interest (which default, in the case of interest only, shall have continued for a period of 30 days or more) on the Notes when and as the same shall become due and payable, whether at stated maturity, by acceleration, by notice of redemption or otherwise; (ii) the Issuer or any Guarantor shall default in the payment of any Additional Amounts as described under “—Additional Amounts” above as and when such amounts shall become due and payable, and such failure shall have continued for a period of 30 days or more; (iii) except as provided in the preceding clauses (i) and (ii), the Issuer or any Guarantor shall default in the performance or observance of certain of the covenants contained in the Notes or Fiscal and Paying Agency Agreement and such default shall continue for more than 90 consecutive days after notice thereof is given by holders of at least 25% in aggregate principal amount of the Notes to the Issuer or such Guarantor; (iv) any Indebtedness or other obligation for borrowed money of the Issuer, any Guarantor or Subsidiaries becomes prematurely due following a default (after any grace period), or the security therefor becomes enforceable, or the Issuer, any Guarantor or Subsidiaries fail to pay on the due date (after any grace period) any loan or Indebtedness, or any guarantee or surety of the Issuer, any Guarantor or Subsidiaries in respect of any Indebtedness or other obligation for borrowed money of the Issuer, the Guarantor or Subsidiaries remains unpaid after 30 days’ notice thereof and the aggregate amount of such Indebtedness is at least US$100,000,000; (v) final judgment or decree for the payment of money shall be rendered by a court of competent jurisdiction against the Issuer or any Guarantor or Subsidiary which, with other outstanding final judgments against the Issuer, any Guarantor or Subsidiary, shall aggregate more than US$100,000,000 (or its equivalent in another currency), and the Issuer, such Guarantor or such Subsidiary, as the case may be, shall not discharge the same or provide for its discharge in accordance with its terms, or procure a stay of execution thereof within 90 days from the date of entry thereof and within said period of 90 days, or such longer period during which execution of such judgment shall have been stayed, appeal therefrom and cause the execution thereof to be stayed during such appeal, exclusive of judgment amounts fully covered by insurance when the insurer has admitted liability in respect of such judgment and has not refused to discharge such liability; (vi) the entry by a court having jurisdiction in the premises of (x) a decree or order for relief against the Issuer, any Guarantor or any Significant Subsidiary in an involuntary case or proceeding under any applicable bankruptcy, liquidation, insolvency, reorganisation or other similar law or (y) a decree or order adjudging the Issuer, any Guarantor or any Significant Subsidiary bankrupt or insolvent, or approving as properly filed a petition seeking reorganisation, arrangement, adjustment or composition of or in respect of the Issuer, any Guarantor or any Significant Subsidiary under any applicable law, or appointing a custodian, receiver, liquidator, assignee, trustee, sequestrator or other similar official of the Issuer, any Guarantor or any Significant Subsidiary or of the whole or substantially the whole of its property, or ordering the

116 winding up or liquidation of its affairs, and, in the case of each of (x) and (y) above, the continuance of any such decree or order for relief or any such other decree or order unstayed and in effect for a period of 90 consecutive days; (vii) the commencement by the Issuer or any Guarantor of a voluntary case or proceeding under any applicable bankruptcy, liquidation, insolvency, reorganisation or other similar law or of any other case or proceeding to be adjudicated a bankruptcy or insolvent, or the consent by it to the entry of a decree or order for relief against the Issuer or any Guarantor in an involuntary case or proceeding under any applicable bankruptcy, liquidation, insolvency, reorganisation or other similar law or to the commencement of any bankruptcy or insolvency case or proceeding against it, or the filing by it of a petition or answer or consent seeking reorganisation or relief under any applicable law, or the consent by it to the filing of such petition or to the appointment of or taking possession by a custodian, receiver, liquidator, assignee, trustee, sequestrator or other similar official of the Issuer or any Guarantor or of the whole or substantially the whole of its respective property, or the making by the Issuer or any Guarantor of an assignment for the benefit of creditors, or the taking of a corporate action by the Issuer or any Guarantor in furtherance of any such action; or (viii) any of the Guarantees ceases to be valid and legally binding for any reason whatsoever, other than a cessation of the Guarantees provided by any Guarantor in connection with a limitation of such Guarantee as described under “—Status of Notes and Guarantees” or a discharge and defeasance of such Guarantee as described under “—Discharge and Defeasance.”

In each and every such case where such Event of Default shall have occurred and be continuing (other than an Event of Default specified in clauses (vi) or (vii) above), the holders of at least 25% in aggregate principal amount of the Notes at the time outstanding may, by written notice to the Issuer, the Guarantors and the Paying Agent, declare the principal of and all accrued interest on the Notes to be due and payable upon the date that written notice is received by or on behalf of the Issuer, the Guarantors and the Paying Agent unless prior to such date all Events of Default in respect of all the Notes shall have been cured. Upon any such declaration, the holders of a majority in the principal amount of all the Notes by notice to the Issuer, the Guarantors and the Paying Agent may rescind an acceleration and its consequences if the rescission would not conflict with any judgment or decree by a court of competent jurisdiction and if all existing Events of Default have been cured or waived except non-payment of principal that has become due solely because of the acceleration. If an Event of Default applicable to the Issuer or any Guarantor specified in clauses (vi) or (vii) above occurs, the principal of and accrued interest on the Notes will be immediately due and payable without any declaration or other act on the part of any holder of Notes.

Modification and Waiver The Fiscal and Paying Agency Agreement contains provisions for convening meetings of holders of the Notes to consider matters affecting their interests. Modifications of and amendments to the Fiscal and Paying Agency Agreement or to the terms and conditions of the Notes or the Guarantees may be made, and future compliance therewith or past default by the Issuer or any Guarantor may be waived with the consent of the holders of at least a majority in aggregate principal amount of the Notes at the time outstanding, or of such lesser percentage as may act at a meeting of holders of the Notes held in accordance with the provisions of the Fiscal and Paying Agency Agreement; provided, however, that without the consent of the holder of each Note so affected, no such modification, amendment, waiver or consent may: • change the stated maturity of the principal or the date of any instalment of interest on any Note, • reduce the principal amount of or interest on any Note or Additional Amounts payable with respect thereto or reduce the amount payable in the event of redemption or default, • change the currency of payment of principal, interest or Additional Amounts, • change the obligation of the Issuer or the Guarantors to pay Additional Amounts (except as otherwise permitted by the Notes), • change the obligations of the Guarantors with respect to the payment of principal of, premium, if any, and interest on any Note (except in connection with a limitation of any of the Guarantees provided by the Guarantors as described under “—Status of Notes and Guarantees”) or a discharge and defeasance of such Guarantee as described under “—Discharge and Defeasance”, • impair the right to institute suit for the enforcement of any such payment on or with respect to the Notes or Guarantees, or

117 • reduce the above-stated percentage of aggregate principal amount of Notes outstanding necessary to: • modify or amend the Fiscal and Paying Agency Agreement or the terms and conditions of the Notes, • waive any future compliance or past default, • reduce the quorum requirements or the percentage of aggregate principal amount of Notes outstanding required for the adoption of any action at a holder’s meeting, or • reduce the percentage of aggregate principal amount of Notes outstanding necessary to rescind or annul any declaration of the principal of and all accrued interest on the Notes to be due and payable.

Without prejudice to the provisions described above, no consent of the holders of any Notes at any time outstanding is or will be required for any modification or amendment requested by the Issuer, the Guarantors and the Fiscal Agent to: • (i) cure any ambiguity or to correct or supplement any provision contained in the Notes, Guarantees, Deed of Covenant or Fiscal and Paying Agency Agreement to correct a manifest error or that may be defective or inconsistent with any other provision contained therein or (ii) to make such other provision in regard to matters or questions arising under the Notes to comply with mandatory provisions of law or as the Issuer may otherwise deem necessary or desirable and which, in the case of (ii), will not in the opinion of the Issuer adversely affect the interests of the holders of the Notes in any material respect; • convey, transfer, assign, mortgage or pledge to the holders of the Notes or any person acting on their behalf as security for the Notes any property or assets; • evidence the succession of another Person to the Issuer or any Guarantor or successive successions, and the assumption by any successor Person of its covenants, agreements and obligations, pursuant to the Notes, Guarantees, Deed of Covenant or Fiscal and Paying Agency Agreement; • evidence and provide for the acceptance of appointment of a successor or successors to the Agent in any of its capacities; • modify the restrictions on, and procedures for, resale and other transfers of the Notes pursuant to law, regulation or practice relating to the resale or transfer of restricted securities generally; or • add to the covenants, restrictions, conditions or provisions of the Issuer or the Guarantors, as the case may be, such further covenants, restrictions, conditions or provisions as the Issuer or the Guarantors, as the case may be, shall consider to be for the protection of the holders of Notes, and to make the occurrence, or the occurrence and continuance, of a default in any such additional covenants, restrictions, conditions or provisions an Event of Default under the Notes permitting the enforcement of all or any of the several remedies provided in the Notes, Guarantees, Deed of Covenant or Fiscal and Paying Agency Agreement; provided that, in respect of any such additional covenant, restriction, condition or provision, the relevant agreement may provide for a particular period of grace after default (which may be shorter or longer than that allowed in the case of other defaults) or may provide for an immediate enforcement upon such an Event of Default or may limit the right of holders of a majority in aggregate principal amount of the Notes to waive such an Event of Default.

Any such modification shall be binding on holders of Notes and any such modification shall be notified to the holders of Notes as soon as practicable thereafter.

Any modifications, amendments or waivers to the Fiscal and Paying Agency Agreement or to the terms and conditions of the Notes, Guarantees or Deed of Covenant will be conclusive and binding on all holders of the Notes, whether or not they have given such consent or were present at such meeting, and on all future holders of Notes, whether or not notation of such modifications, amendments or waivers is made upon the Notes and the Issuer shall communicate such modification, amendment or waiver to the holders of the Notes. Any instrument given by or on behalf of any holder of a Note in connection with any consent to any such modification, amendment or waiver will be conclusive and binding on all subsequent holders of such Note.

At a meeting of the holders of the Notes for the purpose of approving a modification or amendment to, or obtaining a waiver of, any covenant or condition set forth in the Notes or Guarantees, persons entitled to vote at least a majority in aggregate principal amount of the Notes at the time outstanding shall constitute a quorum. In the absence of a quorum at any such meeting, the meeting may be adjourned for a period of not less than ten days; in the absence of a quorum at any such adjourned meeting, such adjourned meeting may be further adjourned for a period of not less than ten days; at the reconvening of any meeting further adjourned for lack of a

118 quorum, the persons entitled to vote at least 25% in aggregate principal amount of the Notes at the time outstanding shall constitute a quorum for the taking of any action set forth in the notice of the original meeting. At a meeting or an adjourned meeting duly convened and at which a quorum is present as aforesaid, any resolution to modify or amend, or to waive compliance with, any of the covenants or conditions referred to above shall be effectively passed if passed by the persons entitled to vote the lesser of (1) at least a majority in aggregate principal amount of Notes then outstanding or (2) at least 75% in aggregate principal amount of the Notes represented and voting at the meeting.

Governing Law, Submission to Jurisdiction and Consent to Service The Notes, the Guarantees, the Deed of Covenant and the Fiscal and Paying Agency Agreement, and any non- contractual obligations arising out of or in connection with them, are governed by and will be construed in accordance with English law. The courts of England are to have exclusive jurisdiction to settle any disputes which may arise out of or in connection with the Notes, the Guarantees, the Deed of Covenant and the Fiscal and Paying Agency Agreement (“Dispute”) and accordingly any legal action or proceedings arising out of or in connection with the Notes, the Guarantees, the Deed of Covenant and the Fiscal and Paying Agency Agreement (“Proceedings”) may be brought in such courts. In the Fiscal and Paying Agency Agreement, the Notes, the Deeds of Guarantee and the Deed of Covenant, the Issuer and each Guarantor, as applicable, will submit to the jurisdiction of such courts and will agree that such courts are the most appropriate and convenient courts to settle any Dispute and will not argue to contrary. These submissions will be made for the benefit of the Paying Agent and each of the holders of the Notes, as applicable, and shall not limit the right of the Agent with respect to the Fiscal and Paying Agency Agreement or the holders of the Notes with respect to the Deed of Covenant, to take Proceedings in any other court of competent jurisdiction nor shall the taking of Proceedings in one or more jurisdictions preclude the taking of Proceedings in any other jurisdiction (whether concurrently or not).

The Issuer and each Guarantor shall, pursuant to the Fiscal and Paying Agency Agreement, the Notes, the Deeds of Guarantee and the Deed of Covenant appoint Petrofac Services Limited, 117 Jermyn Street, London, SW1Y 6HH as its agent in England to receive service of process in any Proceedings in England. Nothing in the Notes, the Deeds of Guarantee, the Deed of Covenant or the Fiscal and Paying Agency Agreement shall affect the right to serve process in any other manner permitted by law.

Regarding the Paying Agent, Transfer Agent and Registrar In acting under the Fiscal and Paying Agency Agreement and in connection with the Notes, the Paying Agent, transfer agent and registrar are acting solely as agents of the Issuer or the Guarantors, as the case may be, and do not assume any obligation towards or relationship of agency or trust for or with the owners or holders of the Notes. Any funds held by any paying agent or registrar for payment of principal of or interest on the Notes shall be held and applied as set forth in the Notes, but need not be segregated from other funds held by it except as required by law. For a description of the duties and the immunities and rights of the Paying Agent, transfer agent and registrar under the Fiscal and Paying Agency Agreement, reference is made to the Fiscal and Paying Agency Agreement, and the obligations of the Paying Agent, transfer agent and registrar to the holder of any Note are subject to such immunities and rights.

Listing The Issuer has applied to list the Notes on the Official List and for the admission of the Notes to trading on the Global Exchange Market, which is the unregulated market of the Irish Stock Exchange. The Issuer has agreed to use its reasonable best efforts to maintain any such listing and admission to trading of the Notes for so long as any of the Notes remain outstanding.

Further Issues The Issuer may from time to time, without notice to or the consent of the holders of the Notes, “reopen” the Notes and create and issue further notes ranking pari passu with and having identical terms and conditions as the Notes in all respects (or in all respects except for the issue date, issue price and the payment of interest accruing prior to the issue date of such further notes or except for the first payment of interest following the issue date of such further notes) so that any such further notes shall be consolidated and form a single series with the Notes and shall have the same terms as to status, redemption or otherwise as the Notes; provided that if such further notes have the same CUSIP, ISIN or other identifying number as the Notes, such further notes must be fungible with the Notes for US federal income tax purposes. Without limiting the foregoing, such holders shall constitute

119 part of the same series for purposes of declaring an Event of Default and such holders shall be entitled to vote on any modifications, amendments or waivers to the terms and conditions of the Notes or to the Fiscal and Paying Agency Agreement with all other holders of the Notes.

Book-Entry System; Delivery and Form See “Book-Entry, Delivery and Form” for more information about the form of the Notes and their clearance and settlement.

120 BOOK-ENTRY, DELIVERY AND FORM

Book-entry System; Delivery and Form Upon issuance, the Notes will be represented by beneficial interests in one or more Global Notes. Each Global Note will be deposited with, or on behalf of, DTC and registered in the name of Cede & Co., as nominee of DTC. Except under the circumstances described below, Global Notes will not be exchangeable at the option of the holder for certificated notes and Global Notes will not otherwise be issuable in definitive form.

Upon issuance of the Global Notes, DTC will credit the respective principal amounts of the Notes represented by the Global Notes to the accounts of institutions that have accounts with DTC or its nominee (called participants of DTC), including Euroclear and Clearstream. The accounts to be credited shall be designated by the Initial Purchasers. Ownership of beneficial interests in the Global Notes will be limited to participants or persons that may hold interests through participants. Ownership of beneficial interest in the Global Notes will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect to participants’ interests) or by participants or persons that hold through participants. Such beneficial interest shall be in denominations of US$2,000 and in multiples of US$1,000 in excess thereof.

So long as DTC, or its nominee, is the registered owner or holder of the Global Notes, DTC or its nominee, as the case may be, will be considered the sole owner and holder of the Global Notes for all purposes under the Fiscal and Paying Agency Agreement.

Except as set forth below, owners of beneficial interests in the Global Notes: • will not be entitled to have the Notes represented by the Global Notes registered in their names, and • will not receive or be entitled to receive physical delivery of Notes in definitive form and will not be considered the owners or holders thereof under the Fiscal and Paying Agency Agreement.

Accordingly, each person owning a beneficial interest in the Global Notes must rely on the procedures of DTC, and indirectly Euroclear and Clearstream, and, if such person is not a participant, on the procedures of the participant through which such person owns its interest, to exercise any rights of a holder under the Fiscal and Paying Agency Agreement.

Principal and interest payments on Global Notes registered in the name of or held by DTC or its nominee will be made to DTC or its nominee, as the case may be, as the registered owner or holder of the Global Notes. None of the Company, the Guarantors, the Paying Agent or the Registrar for such Global Notes will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in Global Notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests.

The Company and the Guarantors expect that DTC, upon receipt of any payments of principal or interest in respect of the Global Notes, will credit the accounts of the related participants (including Euroclear and Clearstream), with payments in amounts proportionate to their respective beneficial interests in the principal amount of the Global Notes as shown on the records of DTC. Payments by participants to owners of beneficial interest in the Global Notes held through such participants will be the responsibility of the participants, as is now the case with securities held for the accounts of customers in bearer form or registered in “street name”.

Unless and until it is exchanged in whole or in part for Notes in definitive form in accordance with the terms of the Fiscal and Paying Agency Agreement, a Global Note may not be transferred except as a whole by the depositary to a nominee of the depositary or by a nominee of DTC to DTC or another nominee of DTC.

If any Note, including a Global Note, is mutilated, defaced, stolen, destroyed or lost, such Note may be replaced with a replacement Note at the office of the registrar or any successor registrar or transfer agent, on payment by the holder of such Note of such costs and expenses as may be incurred in connection with the replacement, and on such terms as to evidence and indemnity as the Company or the Guarantors may reasonably require. Mutilated or defaced Notes must be surrendered before replacement Notes will be issued.

Transfers within Global Notes Subject to the procedures and limitations described herein, transfers of beneficial interests within a Global Note may be made without delivery to the Company, the Guarantors or the Paying Agent of any written certifications or other documentation by the transferor or transferee.

121 Transfers between the Global Notes A beneficial interest in a Rule 144A Global Note may be transferred to a person who wishes to take delivery of such beneficial interest through the applicable Regulation S Global Note only upon receipt by the Paying Agent of a written certification (in the form set out in the Fiscal and Paying Agency Agreement) from the transferor to the effect that such transfer is being made in accordance with Rule 903 or 904 of Regulation S or, in the case of an exchange occurring following the expiration of the distribution compliance period, Rule 144. Prior to the expiration of the distribution compliance period, a beneficial interest in a Regulation S Global Note may be transferred to a person who wishes to take delivery of such beneficial interest through the applicable Rule 144A Global Note only upon receipt by the Paying Agent of a written certification (in the form set out in the Fiscal and Paying Agency Agreement) from the transferor to the effect that such transfer is being made to a person whom the transferor reasonably believes is a QIB within the meaning of Rule 144A, in a transaction meeting the requirements of Rule 144A and in accordance with any applicable securities laws of any state of the United States and any other jurisdiction. After the expiration of the distribution compliance period, such certification requirements will no longer apply to such transfers, but such transfers will continue to be subject to applicable transfer restrictions under the Securities Act and the laws of any state of the United States and other jurisdictions. Any beneficial interest in a Rule 144A Global Note or a Regulation S Global Note that is transferred to a person who takes delivery in the form of a beneficial interest in the other Global Note will, upon transfer, cease to be a beneficial interest in such Global Note and become a beneficial interest in the other Global Note and, accordingly, will thereafter be subject to all transfer restrictions and other procedures applicable to a beneficial interest in such other Global Note for so long as such person retains such an interest.

Exchanges of Global Notes for Definitive Notes Global Notes shall be exchangeable for Definitive Notes registered in the names of persons other than DTC or its nominee for such Global Notes only if: • DTC has notified the Company that it is unwilling or unable to continue as depositary or has ceased to be a clearing agency registered under the Exchange Act, and in either case the Company has failed to appoint a successor depositary within 90 days of such notice, or • there shall have occurred and be continuing an event of default (as defined in the Fiscal and Paying Agency Agreement) with respect to the Notes.

Any Global Note that is exchangeable for definitive notes pursuant to the preceding sentence shall be exchangeable for Notes issuable in denominations of US$2,000 and in multiples of US$1,000 in excess thereof and registered in such names as DTC shall direct. Subject to the foregoing, a Global Note shall not be exchangeable, except for a Global Note of like denomination to be registered in the name of DTC or its nominee. Bearer notes will not be issued.

Transfers from Definitive Notes to Global Notes Definitive Notes, if any, may be transferred or exchanged for a beneficial interest in the relevant Global Note in accordance with the procedures described in the Fiscal and Paying Agency Agreement.

Clearing and Settlement The information set out below in connection with DTC is subject to any change in or reinterpretation of the rules, regulations and procedures of DTC currently in effect. The information about DTC set forth below has been obtained from sources that the Company and the Guarantors believe to be reliable, but none of the Company, the Guarantors or any of the Initial Purchasers takes any responsibility for or makes any representation or warranty with respect to the accuracy of the information. None of the Company, the Guarantors or any of the Initial Purchasers will have any responsibility or liability for any aspect of the records relating to, or payments made on account of interests in Notes held through, the facilities of any clearing system, or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests.

DTC has advised the Company and the Guarantors as follows: DTC is a limited purpose trust company organised under the laws of the State of New York, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for DTC participants and to facilitate the clearance and settlement of transactions between DTC participants through electronic book-entry

122 changes in accounts of DTC participants, thereby eliminating the need for physical movement of certificates. DTC participants include certain of the Initial Purchasers, securities brokers and dealers, banks, trust companies, and clearing corporations, and may in the future include certain other organisations (“DTC participants”). Indirect access to the DTC system is also available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a DTC participant, either directly or indirectly (“indirect DTC participants”).

Under the rules, regulations, and procedures creating and affecting DTC and its operations (the “Rules”), DTC is required to make book-entry transfers of Notes among DTC participants on whose behalf it acts with respect to Notes accepted into DTC’s book-entry settlement system as described below (the “DTC Notes”) and to receive and transmit distributions of the nominal amount and interest on the DTC Notes. DTC participants and indirect DTC participants with which beneficial owners of DTC Notes (“Owners”) have accounts with respect to the DTC Notes similarly are required to make book-entry transfers and receive and transmit such payments on behalf of their respective Owners. Accordingly, although Owners who hold DTC Notes through DTC participants or indirect DTC participants will not possess Notes, the Rules, by virtue of the requirements described above, provide a mechanism by which such Owners will receive payments and will be able to transfer their interests with respect to the Notes.

Transfers of ownership or other interests in the Notes in DTC may be made only through DTC participants. Indirect DTC participants are required to effect transfers through a DTC participant. DTC has no knowledge of the actual beneficial owners of the Notes. DTC’s records reflect only the identity of the DTC participants to whose accounts the Notes are credited, which may not be the beneficial owners. DTC participants will remain responsible for keeping account of their holdings on behalf of their customers and for forwarding all notices concerning the Notes to their customers. So long as DTC, or its nominee, is the registered holder of a Global Note, payments on the Notes will be made in immediately available funds to DTC. DTC’s practice is to credit DTC participants’ accounts on the applicable payment date in accordance with their respective holdings shown on its records, unless DTC has reason to believe that it will not receive payment on that date. Payments by DTC participants to beneficial owners will be governed by standing instructions and customary practices, and will be the responsibility of the DTC participants and not of DTC, or any other party, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment to DTC is the responsibility of the Paying Agent. Disbursement of payments for DTC participants will be DTC’s responsibility, and disbursement of payments to the beneficial owners will be the responsibility of DTC participants and indirect DTC participants.

Because DTC can only act on behalf of DTC participants, who in turn act on behalf of indirect DTC participants, and because owners of beneficial interests in the Notes holding through DTC will hold interests in the Notes through DTC participants or indirect DTC participants, the ability of the owners of the beneficial interests to pledge Notes to persons or entities that do not participate in DTC, or otherwise take actions with respect to the Notes, may be limited. DTC will take any action permitted to be taken by an Owner only at the direction of one or more DTC participants to whose account with DTC such Owner’s DTC Notes are credited. Additionally, DTC has advised the Company that it will take such actions with respect to any percentage of the beneficial interest of Owners who hold Notes through DTC participants or indirect participants only at the direction of and on behalf of DTC participants whose account holders include undivided interests that satisfy any such percentage.

To the extent permitted under applicable law and regulations, DTC may take conflicting actions with respect to other undivided interests to the extent that such actions are taken on behalf of DTC participants whose account holders include such undivided interests.

Ownership of interests in the Rule 144A Global Notes and the Regulation S Global Notes will be shown on, and the transfer of that ownership will be effected only through records maintained by, DTC, the DTC participants and the indirect DTC participants, including Euroclear and Clearstream. Transfers between participants in DTC, as well as transfers between participants in Euroclear and Clearstream will be effected in the ordinary way in accordance with DTC rules.

Subject to compliance with the transfer restrictions applicable to the Notes, cross-market transfers between DTC, on the one hand, and participants in Euroclear or Clearstream on the other hand, will be effected in DTC in accordance with DTC rules on behalf of Euroclear or Clearstream, as the case may be. Such cross-market transactions, however, will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with its rules and procedures and within its established deadlines.

123 Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to DTC to take action to effect final settlement on its behalf by delivering or receiving payment in accordance with DTC’s Same-Day Funds Settlement System.

According to DTC, the foregoing information with respect to DTC has been provided to the industry for informational purposes only and is not intended to serve as a representation, warranty or contract modification of any kind. Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures in order to facilitate transfers of interests in the Global Notes among participants of DTC, Euroclear and Clearstream, they are under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. None of the Company, the Guarantors or the Paying Agent will have any responsibility for the performance by DTC, Euroclear or Clearstream, or their respective participants or indirect participants, of their respective obligations under the rules and procedures governing their operations.

Initial Settlement in Relation to DTC Notes Upon the issuance of a DTC Note deposited with DTC or a custodian therefore, DTC or its custodian, as the case may be, will credit, on its internal system, the respective nominal amount of the individual beneficial interest represented by such relevant DTC Note or Notes to the accounts of persons who have accounts with DTC. Such accounts initially will be designated by or on behalf of the relevant Initial Purchasers. Ownership of beneficial interest in a DTC Note will be limited to DTC participants, including Euroclear and Clearstream, or indirect DTC participants. Ownership of beneficial interests in DTC Notes will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect to interests of DTC participants) and the records of DTC participants (with respect to interests of indirect DTC participants). Investors that hold their interests in a DTC Note will follow the settlement procedures applicable to global bond issues. Investors’ securities custody accounts will be credited with their holdings against payment in same-day funds on the settlement date.

Secondary Market Trading in Relation to DTC Notes Since the purchaser determines the place of delivery, it is important to establish at the time of the trade where both the purchaser’s and seller’s accounts are located to ensure that settlement can be made on the desired value date. Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in Global Notes deposited with DTC or a custodian therefore among participants of DTC, DTC is under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. Neither the Company nor any agent of the Company will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations. Secondary market trading between DTC participants will be settled using the procedures applicable to global bond issues in same-day funds.

124 TAXATION

The following is a general description of certain tax considerations relating to the Notes and does not purport to be a complete analysis of tax considerations relating to the Notes (including such tax laws and practices as they apply to any land or building situated in Jersey).

Prospective purchasers of the Notes are advised to consult their own tax advisers as to the tax consequences, under the tax laws of the country of which they, the Issuer or the Guarantor are resident, of a purchase of Notes including, without limitation, the consequences of receipt of interest and premium, if any, on and sale or redemption of, the Notes or any interest therein.

The information and analysis contained within this section are limited to tax issues, and prospective investors should not apply any information or analysis set out below to other areas, including (but not limited to) the legality of transactions involving the Notes.

Jersey Taxation Taxation of the Company The Company is regarded as resident for tax purposes in Jersey and on the basis that the Company is neither a financial services company nor a utility company for the purposes of the Income Tax (Jersey) Law 1961, as amended, the Company is subject to income tax in Jersey at a rate of zero percent. Payments in respect of the Notes may be paid by the Company without withholding or deduction for or on account of Jersey income tax and holders of Notes (other than residents of Jersey) will not be subject to any tax in Jersey in respect of the holding, sale or other disposition of such Notes. Payments by Petrofac International Ltd as a Guarantor may be paid by Petrofac International Ltd without withholding or deduction for or on account of Jersey income tax. Holders of Notes (other than residents of Jersey) will not be subject to any tax in Jersey in respect of the holding, sale or other disposition of such Notes.

Stamp duty In Jersey, no stamp duty is levied on the issue or transfer of the Notes except that stamp duty is payable on Jersey grants of probate and letters of administration, which will generally be required to transfer the Notes on the death of a holder of such Notes. In the case of a grant of probate or letters of administration, stamp duty is levied according to the size of the estate (wherever situate in respect of a holder of Notes domiciled in Jersey, or situate in Jersey in respect of a holder of Notes domiciled outside Jersey) and is payable on a sliding scale at a rate of up to 0.75% of such estate and such duty is capped at £100,000.

Jersey does not otherwise levy taxes upon capital, inheritances, capital gains or gifts nor are there other estate duties.

EU Savings Directive As part of an agreement reached in connection with the EU Savings Directive on the taxation of savings income in the form of interest payments, and in line with steps taken by other relevant third countries, Jersey has introduced a retention tax system in respect of payments of interest, or other similar income, made to an individual beneficial owner resident in a Member State by a paying agent established in Jersey. The retention tax system applies for a transitional period prior to the implementation of a system of automatic communication to Member States of information regarding such payments. During this transitional period, such an individual beneficial owner resident in a Member State will be entitled to request a paying agent not to retain tax from such payments but instead to apply a system by which the details of such payments are communicated to the tax authorities of the Member State in which the beneficial owner is resident.

The retention tax system in Jersey is implemented by means of bilateral agreements with each of the Member States, the Taxation (Agreements with EU Member States) (Jersey) Regulations 2005 and Guidance Notes issued by the Policy & Resources Department of the States of Jersey (being the predecessor to the Chief Minister’s Department of the States of Jersey). Based on these provisions and what is understood to be the current practice of the Jersey tax authorities, the Company would not be obliged to levy retention tax in Jersey under these provisions in respect of interest payments made by it to a paying agent established outside Jersey.

125 The UAE Taxation One of the Guarantors, Petrofac International (UAE) LLC, is incorporated under the laws of the Emirate of Sharjah, the UAE. There is no Federal Law on taxation in the UAE.

Income Tax Each of the Emirates in the UAE has promulgated its own Income Tax Decree that provides for progressive levels of taxation on the income of corporate persons. However, in practice, the tax is collected only from foreign hydrocarbon-producing companies and foreign banks. No income tax is collected from any other corporate persons in the UAE. No income tax applies to the income of natural persons.

Other Taxes and Levies Subject to the limited exceptions, there is no sales tax, withholding tax, capital gains tax, stamp duty or VAT applicable in the UAE. There are, however, fees charged for various government transactions and services, including fees for the incorporation of a company, for the notarisation of a signature, for the registration of an interest in the real estate and for the registration of a motor vehicle, an aircraft or a ship.

Foreign Exchange Control No foreign-exchange controls are imposed by either the federal government of the UAE or the individual Emirates.

Tax Consequences Holders of Notes will not be subject to any tax in the UAE in respect of the holding, sale or other disposition of such Notes. It is also unlikely that any other aspect of the Offering will involve UAE tax consequences, unless a Sharjah court action is required to enforce an obligation of the UAE Guarantor, in which case, court fees will apply and translation and authentication costs might be incurred or imposed in respect of evidentiary material submitted in the court proceedings.

United States Taxation The following is a summary based on present law of certain US federal income tax considerations relevant to the purchase, ownership and disposition of the Notes by a US Holder (as defined below). This discussion addresses only US Holders who purchase Notes in the original offering at their original offering price, hold the Notes as capital assets and use the US dollar as their functional currency. This discussion is not a complete description of all US federal income tax considerations relating to the purchase, ownership and disposition of the Notes or the Offering.

It does not address all of the tax considerations relevant to US Holders subject to special rules, such as banks, dealers, traders that elect to mark-to-market, insurance companies, investors liable for the alternative minimum tax, US expatriates, tax-exempt entities or persons holding Notes as part of a hedge, straddle, conversion or other integrated financial transaction. It also does not address US state and local or non- US tax considerations.

THE FOLLOWING STATEMENTS ABOUT US FEDERAL TAX ISSUES ARE MADE TO SUPPORT MARKETING OF THE NOTES. NO TAXPAYER CAN RELY ON THEM TO AVOID TAX PENALTIES. EACH US HOLDER SHOULD SEEK ADVICE FROM AN INDEPENDENT TAX ADVISOR ABOUT THE US AND NON-US TAX CONSEQUENCES TO IT UNDER ITS OWN PARTICULAR CIRCUMSTANCES OF AN INVESTMENT IN THE NOTES.

For purposes of this discussion, a “US Holder” is a beneficial owner of Notes that is, for purposes of US federal income taxation, (i) a citizen or individual resident of the United States, (ii) a corporation or other business entity treated as a corporation created or organised under the laws of the United States or its political subdivisions, (iii) a trust subject to the control of a US person and the primary supervision of a US court or (iv) an estate the income of which is subject to US federal income taxation regardless of its source.

The US federal income tax treatment of a partner in a partnership (or other entity treated as a partnership for US federal income tax purposes) that acquires or holds Notes generally will depend upon the status of the partner and the activities of the partnership. Partners in a partnership that acquires or holds Notes should consult their own tax advisors regarding the specific tax consequences to them of the partnership acquiring, owning and disposing of the Notes.

126 Characterisation of the Notes The Notes provide for contingent payments in the event of a Change of Control Repurchase Event. The Company intends to take the position that the possibility of such payments does not result in the Notes being treated as contingent payment debt instruments for US federal income tax purposes, and the remainder of this disclosure assumes that the Notes are not so treated, but no assurance can be given that the Internal Revenue Service (“IRS”) will not assert a contrary position. Our position is binding on a US Holder unless such holder discloses that it is taking a contrary position in the manner required by applicable US Treasury regulations. Our position is not, however, binding on the IRS, and if the IRS were to successfully assert a contrary position, all stated interest received by US Holders would be treated as original issue discount, a US Holder might be required to accrue income on the Notes in excess of stated interest and a US Holder’s gain on a sale or other taxable disposition of the Notes would be treated as ordinary income. Prospective purchasers of the Notes should consult their own tax advisors regarding the treatment of the Notes as contingent payment debt instruments.

Interest Interest on the Notes, including Additional Amounts, if any, generally will be includible in the gross income of a US Holder in accordance with such holder’s regular method of tax accounting. The interest generally will be ordinary income from sources outside the United States and generally will be considered “passive category income” or, in the case of certain US Holders, “general category income” for foreign tax credit purposes.

Interest received by certain non-corporate US Holders generally will be includible in computing “net investment income” for purposes of the 3.8% Medicare contribution tax.

Disposition of Notes A US Holder generally will realise capital gain or loss upon a sale, exchange, retirement or other taxable disposition of a Note in an amount equal to the difference between the amount realised from such disposition (less any accrued and unpaid stated interest, which will be taxable as interest as described above) and the US Holder’s adjusted tax basis in the Note. A US Holder’s adjusted tax basis in a Note generally will equal the US Holder’s cost of the Note. Gain or loss recognised on the transaction generally will be US source capital gain or loss and will be long-term capital gain or loss if the Note has been held for more than one year. Long-term capital gains of non-corporate US Holders may be taxed at lower rates. Deductions for capital losses are subject to limitations. Gain realised by certain non-corporate US Holders will generally be includible in computing “net investment income” for purposes of the 3.8% Medicare contribution tax.

Information Reporting and Backup Withholding Payments of interest, principal or the proceeds from the sale, exchange, retirement or other taxable disposition of a Note that are made within the United States or through certain US related financial intermediaries may be reported to the IRS unless the holder is a corporation or otherwise establishes a basis for exemption. Backup withholding tax may apply to amounts subject to reporting if a holder of a Note fails to provide an accurate taxpayer identification number or fails to report all interest and dividends required to be shown on a US federal income tax return. A US Holder can claim a credit against US federal income tax liability for amounts withheld under the backup withholding rules and can claim a refund of amounts in excess of its liability for US federal income tax by timely providing required information to the IRS. Prospective investors should consult their tax advisors as to their qualification for exemption from backup withholding and the procedure for establishing an exemption.

Certain US Holders are required to report to the IRS information with respect to their investment in the Notes not held through an account with a financial institution. Investors who fail to report required information could become subject to substantial penalties. Prospective investors are encouraged to consult with their own tax advisors regarding information reporting requirements with respect to their investment in the Notes.

EU Savings Directive Under the EU Savings Directive, each Member State of the European Union (each a “Member State”) is required to provide to the tax authorities of any other Member State details of payments of interest or similar

127 income (similar income for this purpose includes, but is not limited to, payments on redemption of the Notes representing any discount on the issue of the Notes or any premium payable on redemption) paid by a person within its jurisdiction to or for the benefit of, or collected by such person for, an individual resident in that other Member State or to certain limited types of entities established in that other Member State. However, for a transitional period, Luxembourg and Austria are instead required (unless during that period they elect otherwise) to operate a withholding system in relation to such payments (the ending of such transitional period being dependent upon the conclusion of certain other agreements relating to information exchange with certain other countries), deducting tax at a rate of 35%. A number of non-EU countries and territories including Switzerland have adopted similar measures (a withholding system in the case of Switzerland). On 10 April 2013, the Luxembourg Ministry of Finance announced that Luxembourg’s transitional period will end with effect from 1 January 2015.

The European Commission has proposed certain amendments to the EU Savings Directive, which may, if implemented, amend or broaden the scope of the requirements described above.

THE DISCUSSION ABOVE IS A GENERAL SUMMARY. IT DOES NOT COVER ALL TAX MATTERS THAT MAY BE IMPORTANT TO A PARTICULAR INVESTOR. EACH PROSPECTIVE INVESTOR IS URGED TO CONSULT ITS OWN TAX ADVISOR ABOUT THE TAX CONSEQUENCES TO IT OF AN INVESTMENT IN THE NOTES.

128 PLAN OF DISTRIBUTION

The Company and the Guarantors have entered into a purchase agreement, dated 3 October 2013, with the Initial Purchasers pursuant to which, and subject to the conditions therein, we have agreed to sell to the Initial Purchasers, and the Initial Purchasers have agreed to purchase from us, the principal amount of the Notes set forth opposite their names below:

Principal Amount of the Initial Purchasers Notes Barclays Capital Inc...... US$300,000,000 J.P. Morgan Securities LLC ...... US$300,000,000 Deutsche Bank Securities Inc...... US$ 75,000,000 RBS Securities Inc...... US$ 75,000,000 Total ...... US$750,000,000

The purchase agreement provides that the Initial Purchasers’ obligation to purchase the Notes depends on the satisfaction of the conditions contained in the purchase agreement including: • the obligation to purchase all of the Notes offered hereby, if any of the Notes are purchased; • the representations and warranties made by the Company and the Guarantors to the Initial Purchasers are true; • there is no material change in our business or the financial markets; and • the Company and the Guarantors deliver customary closing documents to the Initial Purchasers.

The Initial Purchasers will purchase the Notes at a customary discount from the offering price indicated on the cover of this Offering Memorandum and propose initially to offer and sell the Notes at the offering price set forth on the front of this Offering Memorandum. After the initial offering of the Notes, the offering price at which the Notes are being offered may be changed at any time without notice.

Lock-Up The Company and the Guarantors have each agreed not to, for a period from the date hereof until the date of delivery of the Notes, without the prior written consent of the Initial Purchasers, directly or indirectly, issue, sell, offer to sell, grant any option for the sale of, or otherwise dispose of, any debt securities that are substantially similar to the Notes and the Guarantees (including, without, limitation with respect to the maturity, currency, interest rate and other material terms thereof).

Indemnification We have agreed to indemnify the Initial Purchasers against certain liabilities, including liabilities under the Securities Act, or to contribute to payments that the Initial Purchasers may be required to make for these liabilities.

Stabilisation and Short Positions In connection with this Offering, the Initial Purchasers may engage in certain transactions that stabilise, maintain or otherwise affect the price of the Notes. Specifically, the Initial Purchasers may overallot in connection with the offering of the Notes, creating a syndicate short position. In addition, the Initial Purchasers may bid for and purchase Notes in the open market to cover syndicate short positions or to stabilise the price of the Notes. Any of these activities may stabilise or maintain the market price of the Notes above what it would be in the absence of such activities. The Initial Purchasers are not required to engage in any of these activities, and they may end any of them at any time. We and the Initial Purchasers make no representation as to the direction or magnitude of any effect that the transactions described above may have on the price of the Notes. In addition, neither we nor any of the Initial Purchasers make any representation that anyone will engage in such transactions or that such transactions, once commenced, will not be discontinued without notice.

129 Settlement We expect that delivery of the Notes will be made against payment therefor on or about the closing date specified on the coverage page of this Offering Memorandum, which will be the fifth business day following the date of pricing of the Notes (this settlement cycle being referred to as “T+5”). Under Rule 15c6-1 of the Exchange Act, trades in the secondary market generally are required to settle in three business days, unless the parties to any such trade expressly agree otherwise. Accordingly, purchasers who wish to trade Notes on the date of pricing or the immediately succeeding business day will be required, by virtue of the fact that the Notes initially will settle T+5, to specify an alternate settlement cycle at the time of any such trade to prevent a failed settlement. Purchasers of notes who wish to trade notes on the date of pricing or the immediately succeeding business days should consult their own advisors.

Relationships (Conflicts of Interest) The Initial Purchasers and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The Initial Purchasers and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for the Company and its affiliates, for which they received or may in the future receive customary fees and expenses. Affiliates of certain of the Initial Purchasers are lenders under our Revolving Credit Facility. To the extent the proceeds of the Offering are used to repay indebtedness under our Revolving Credit Facility, such affiliates of the Initial Purchasers will receive a portion of the proceeds of the Notes.

In the ordinary course of their various business activities, the Initial Purchasers and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of the Company or its affiliates. If any of the Initial Purchasers or their affiliates have a lending relationship with us, certain of those Initial Purchasers or their affiliates routinely hedge, and certain other of those underwriters or their affiliates may hedge, their credit exposure to us consistent with their customary risk management policies. The Initial Purchasers and their affiliates may hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the Notes offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the Notes offered hereby. The Initial Purchasers and certain of their affiliates may also communicate independent investment recommendations, market colour or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Rule 144A and Regulation S The Notes have not been registered under the Securities Act or any state securities laws, and unless so registered, 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) except pursuant to an exemption from or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. See “Notice to Investors”. The Notes have no established trading market and application has been made to the Irish Stock Exchange for the Notes to be admitted to the Official List and trading on the Global Exchange Market. The Initial Purchasers have advised us of their intention to make a market for the Notes, but have no obligation to do so and may discontinue market-making at any time without providing any notice. We cannot assure you as to the liquidity of any trading market for the Notes.

We have been advised by the Initial Purchasers that the Initial Purchasers propose to resell these notes to (a) qualified institutional buyers in reliance on Rule 144A under the Securities Act and (b) outside the US to certain non-US persons in reliance on Regulation S under the Securities Act. See “Notice to Investors”. Any offer or sale of the notes in reliance on Rule 144A will be made by broker-dealers who are registered as such under the Exchange Act.

The Initial Purchasers have acknowledged and agreed that, except as permitted by the purchase agreement, in connection with sales outside the United States, they will not offer, sell or deliver the Notes to, or for the account or benefit of US persons (a) as part of their distribution at any time or (b) otherwise until 40 days after the later of

130 the commencement of the Offering or the date the notes were originally issued. The Initial Purchasers will send to each dealer to whom they sell the notes in reliance on Regulation S during the 40-day distribution compliance period, a confirmation or other notice setting forth the restrictions on offers and sales of the notes within the United States or to, or for the account or benefit of, US persons. Terms used in this paragraph have the meanings assigned to them in Regulation S under the Securities Act.

In addition, until the expiration of the 40-day distribution compliance period referred to above, an offer or sale of the Notes within the United States by a dealer (whether or not participating in this Offering) may violate the registration requirements of the Securities Act if such offer or sale is made otherwise than in accordance with Rule 144A under the Securities Act or pursuant to another exemption from registration under the Securities Act.

131 NOTICE TO INVESTORS

You are advised to consult legal counsel prior to making any offer, resale, pledge or other transfer of any of the Notes offered hereby.

The Notes and Guarantees have not been registered under the Securities Act or any state securities laws and, unless so registered, may not be offered or sold except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. Accordingly, the Notes offered hereby are being offered and sold only to “qualified institutional buyers” (as defined in Rule 144A under the Securities Act) in reliance on Rule 144A under the Securities Act and in offshore transactions to purchasers who are not US Persons (as defined in Regulation S under the Securities Act) in reliance on Regulation S under the Securities Act.

In addition, until 40 days after the later of the commencement of the Offering and the closing date, an offer or sale of the Notes within the United States by a dealer (whether or not participating in the Offering) may violate the registration requirements of the Securities Act if such offer or sale is made otherwise than pursuant to Rule 144A.

Each purchaser of Notes, by its acceptance thereof, will be deemed to have acknowledged, represented to and agreed with us and the Initial Purchasers as follows: 1. It understands and acknowledges that the Notes and the Guarantees have not been registered under the Securities Act or any other applicable securities law, are being offered for resale in transactions not requiring registration under the Securities Act and any other securities law, including sales pursuant to Rule 144A under the Securities Act, and may not be offered, sold or otherwise transferred except in compliance with the registration requirements of the Securities Act or any other applicable securities law, pursuant to an exemption therefrom or in any transaction not subject thereto and in each case in compliance with the conditions for transfer set forth in paragraphs (4) and (5) below. 2. It is not an “affiliate” (as defined in Rule 144 under the Securities Act) of the Company or any Guarantor and is not or acting on the Company’s behalf or that of a Guarantor and it is either: (a) a qualified institutional buyer, or QIB, within the meaning of Rule 144A under the Securities Act and is aware that any sale of Notes to it will be made in reliance on Rule 144A under the Securities Act, of which the acquisition will be for its own account or for the account of another QIB; or (b) is not a US Person, and is not purchasing for the account or benefit of a US Person, and is purchasing the Notes in an offshore transaction in accordance with Regulation S under the Securities Act. 3. It acknowledges that none of the Company, the Guarantors, the Initial Purchasers, or any person representing us, our subsidiaries or the Initial Purchasers, has made any representation to it with respect to the Offering or sale of any Notes, other than the information contained in this Offering Memorandum, which document has been delivered to it and upon which it is relying in making its investment decision with respect to the Notes. It acknowledges that it has had access to such financial and other information concerning the Company, the Guarantors, the Notes and the Guarantees as it has deemed necessary in connection with its decision to purchase any of the Notes. 4. It is purchasing the Notes for its own account, or for one or more investor accounts for which it is acting as a fiduciary or agent, in each case for investment, and not with a view to, or for offer or sale in connection with, any distribution thereof in violation of the Securities Act or any state securities laws, subject to any requirement of law that the disposition of its property or the property of such investor account or accounts be at all times within its or their control and subject to its or their ability to resell such Notes pursuant to Rule 144A, Regulation S or any other exemption from registration available under the Securities Act. 5. It understands and agrees that if in the future it decides to offer, resell, pledge or otherwise transfer any of the Notes or any beneficial interest in the Notes (in the case of the Notes represented by a Regulation S Global Note, prior to the date which is forty days after the later of the date the Notes were first offered and the date of the issuance of the notes), it will only do so (i) to us or any of our subsidiaries, (ii) for so long as the notes are eligible pursuant to Rule 144A under the Securities Act to a person whom the seller reasonably believes is a QIB in a transaction meeting the requirements of Rule 144A, (iii) outside the United States in compliance with Rule 904 under the Securities Act, (iv) pursuant to another exemption from registration under the Securities Act (if available), (v) pursuant to an effective registration statement under the Securities Act, and in each of these cases (i) through (v) in accordance with any applicable securities laws of any state

132 of the United States or any other relevant jurisdictions. Subject to the procedures set forth under “Book- Entry System; Delivery and Form”, prior to any proposed transfer of any Note the holder thereof must check the appropriate box set forth on its Note relating to the manner of such transfer and submit the Note to the Paying Agent. 6. It understands that the Notes will bear a legend to the following effect unless otherwise agreed by us and the holder thereof:

Legend Rule 144A Global Note:

“NEITHER THIS NOTE NOR ANY BENEFICIAL INTEREST HEREIN HAS BEEN REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”). THE HOLDER HEREOF, BY PURCHASING THIS NOTE, AGREES FOR THE BENEFIT OF PETROFAC LIMITED (THE “ISSUER”) AND ANY OF ITS SUCCESSORS IN INTEREST, THAT THIS NOTE MAY BE OFFERED, SOLD, PLEDGED OR OTHERWISE TRANSFERRED ONLY (1) TO THE ISSUER OR ANY SUBSIDIARY THEREOF, (2) SO LONG AS THIS NOTE IS ELIGIBLE FOR RESALE PURSUANT TO RULE 144A UNDER THE SECURITIES ACT (“RULE 144A”), TO A PERSON WHO THE SELLER REASONABLY BELIEVES IS A QUALIFIED INSTITUTIONAL BUYER (AS DEFINED IN RULE 144A) PURCHASING FOR ITS OWN ACCOUNT OR THE ACCOUNT OF ONE OR MORE OTHER QUALIFIED INSTITUTIONAL BUYERS IN ACCORDANCE WITH RULE 144A, (3) IN AN OFFSHORE TRANSACTION COMPLYING WITH RULE 903 OR RULE 904 (AS APPLICABLE) OF REGULATION S UNDER THE SECURITIES ACT, (4) PURSUANT TO ANOTHER EXEMPTION FROM REGISTRATION UNDER THE SECURITIES ACT (IF AVAILABLE), OR (5) PURSUANT TO AN EFFECTIVE REGISTRATION STATEMENT UNDER THE SECURITIES ACT, IN EACH SUCH CASE IN ACCORDANCE WITH ANY APPLICABLE SECURITIES LAWS OF ANY STATE OF THE UNITED STATES OR OTHER JURISDICTIONS. THE HOLDER HEREOF, BY PURCHASING THIS NOTE, REPRESENTS AND AGREES FOR THE BENEFIT OF THE ISSUER, AND ANY OF ITS SUCCESSORS IN INTEREST, THAT IT WILL NOTIFY ANY PURCHASER OF THIS NOTE FROM IT OF THE RESALE RESTRICTIONS REFERRED TO ABOVE AND WILL REQUIRE THAT A CERTIFICATE OF TRANSFER IN THE FORM APPEARING ON THE OTHER SIDE OF THIS NOTE IS COMPLETED AND DELIVERED BY THE TRANSFEROR TO THE FISCAL AGENT. THIS LEGEND WILL BE REMOVED ONLY AT THE OPTION OF THE ISSUER”.

Legend Regulation S Global Note:

“THIS NOTE HAS NOT BEEN REGISTERED UNDER THE UNITED STATES SECURITIES ACT OF 1933, AS AMENDED (THE “SECURITIES ACT”) AND MAY NOT BE OFFERED, SOLD OR DELIVERED IN THE UNITED STATES OR TO, OR FOR THE ACCOUNT OR BENEFIT OF, ANY US PERSON, UNLESS SUCH NOTES ARE REGISTERED UNDER THE SECURITIES ACT OR AN EXEMPTION FROM THE REGISTRATION REQUIREMENTS THEREOF IS AVAILABLE. THIS LEGEND SHALL BE REMOVED AFTER THE EXPIRATION OF FORTY DAYS FROM THE LATER OF (i) THE DATE ON WHICH THIS NOTE WAS FIRST OFFERED AND (ii) THE DATE OF ISSUANCE OF THIS NOTE”. 7. It agrees that it will give to each person to whom it transfers the notes notice of any restrictions on transfer of such notes. 8. It represents and agrees that (i) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity within the meaning of Section 21 of the FSMA received by it in connection with the issue or sale of any securities in circumstances in which Section 21(1) of the FSMA does not apply to us; and (ii) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to any securities in, from or otherwise involving the United Kingdom. 9. It represents and agrees that (i) it is able to fend for itself in the transactions contemplated by this document; (ii) no other representation with respect to the offer or sale of the notes has been made, other than the information contained in this document; (iii) the investment decision is solely based on the information contained in this Offering Memorandum; (iv) the Initial Purchasers make no representation or warranty as to the accuracy or completeness of this document; and (v) it has such knowledge and experience in financial and business matters as to be capable of evaluating the merits and risks of its prospective investment and can afford the complete loss of such investment. 10. It acknowledges that the fiscal agent will not be required to accept for registration of transfer any notes except upon presentation of evidence satisfactory to us and the fiscal agent that the restrictions set forth therein have been complied with.

133 11. It acknowledges that we, the Initial Purchasers and others will rely upon the truth and accuracy of the foregoing acknowledgements, representations, warranties and agreements and agrees that if any of the acknowledgements, representations, warranties and agreements deemed to have been made by its purchase of the notes are no longer accurate, it shall promptly notify the Initial Purchasers. If it is acquiring any notes as a fiduciary or agent for one or more investor accounts, it represents that it has sole investment discretion with respect to each such investor account and that it has full power to make the foregoing acknowledgements, representations and agreements on behalf of each such investor account.

134 LEGAL MATTERS

Certain legal matters in connection with the Offering will be passed upon for us by Freshfields Bruckhaus Deringer LLP, as to matters of US and English law; by Carey Olsen as to Jersey law; and by Afridi & Angell as to the laws of the Emirate of Sharjah, the UAE.

Certain legal matters in connection with the Offering will be passed upon for the Initial Purchasers by Davis Polk & Wardwell London LLP as to matters of US and English law.

135 INDEPENDENT AUDITORS

Ernst & Young LLP, independent auditors, have reviewed the Company’s 2013 Interim Condensed Consolidated Financial Statements for the six months ended 30 June 2013 and have audited the Company’s Consolidated Financial Statements for the years ended 31 December 2012, 2011 and 2010, as stated in their reports appearing therein. The Financial Statements begin on page F-1 of this Offering Memorandum. Ernst & Young LLP is registered to carry out audit work by the Institute of Chartered Accountants in England and Wales.

136 WHERE YOU CAN FIND MORE INFORMATION

We are not currently subject to the periodic reporting and other information requirements of the Exchange Act. However, so long as the Notes are outstanding, we will furnish periodic information to holders of the Notes. Please see “Description of Notes and Guarantees—Covenants of the Issuer and the Guarantors—Information”.

Each purchaser of the Notes from the Initial Purchasers will be furnished with a copy of this Offering Memorandum and, to the extent provided to the Initial Purchasers by us for such purpose, any related amendment or supplement to this Offering Memorandum. Each person receiving the Offering Memorandum acknowledges that: (i) such person has been afforded an opportunity to request from us and to review, and has received, all additional information considered by it to be necessary to verify the accuracy and completeness of the information herein; (ii) such person has not relied on any of the Initial Purchasers or any person affiliated with any Initial Purchaser in connection with its investigation of the accuracy of such information or its investment decision; and (iii) except as provided pursuant to (i) above, no person has been authorised to give any information or to make any representation concerning the Notes or the Guarantees offered hereby other than those contained herein and, if given or made, such other information or representation should not be relied upon as having been authorised by us or any Initial Purchaser. We have agreed that we will, during any period in which we are neither subject to Section 13 or 15(d) of the Exchange Act, nor exempt from reporting pursuant to Rule 12g3-2(b) of the Exchange Act, upon written request of a holder or beneficial owner of the Notes, furnish to such holder or beneficial owner or to the Paying Agent for delivery to such holder or beneficial owner or prospective purchaser of the Notes, as the case may be, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act, to permit compliance with Rule 144A thereunder in connection with resales of the Notes. Any such request should be directed to the Company at Petrofac Limited, Ogier House, The Esplanade, St Helier, Jersey JE4 9WG.

So long as the Notes are admitted to trading on the Irish Stock Exchange’s Global Exchange Market and to listing on the Official List of the Irish Stock Exchange, and the rules and regulations of such stock exchange so require, copies of such information will also be available for review during the normal business hours on any business day at the specified office of the Company. In addition, copies of the Fiscal and Paying Agency Agreement, the Deed of Covenant, the form of Note and the Deeds of Guarantee may be requested from the Company.

The creation and issue of the Notes have been authorised by the Company’s Board of Directors. The creation and issue of the Guarantees have been authorised by the respective board of directors of each Guarantors.

137 SERVICE OF PROCESS AND ENFORCEMENT OF JUDGMENTS

We are a public limited company incorporated under the laws of Jersey. The documents governing the Securities will be governed by English law. The Company and Petrofac International Ltd, a Guarantor, are limited companies incorporated with limited liability under the laws of Jersey. Petrofac International (UAE) LLC, a Guarantor, is a limited liability company incorporated under the laws of the Emirate of Sharjah, the UAE. All or a substantial portion of the Company and the Guarantors’ Directors and Senior Management reside outside the United States and all or a substantial portion of the assets of such persons and the assets of the Company and the Guarantors are located outside the United States. As a result, it may not be possible for investors to effect service of process within the United States upon our Directors or members of Senior Management named in this document or obtain or enforce, in US courts, judgments obtained outside US courts against the Directors or members of Senior Management in any action, including actions under US securities laws. There can be no assurance that civil liabilities predicated upon federal securities laws of the United States will be enforceable in the United Kingdom.

Jersey The United States and Jersey currently do not have a treaty providing for the reciprocal recognition and enforcement of judgments (as opposed to arbitration awards) in civil and commercial matters. Consequently, a final judgment for payment rendered by any federal or state court in the United States based on civil liability, whether or not predicated solely upon US federal securities laws, would not automatically be recognised or enforceable in Jersey. In order to enforce any such US judgment in Jersey, proceedings must first be initiated before a court of competent jurisdiction in Jersey. In such an action, a Jersey court would not generally reinvestigate the merits of the original matter decided by the US court (subject to what is said below) and it would usually be possible to obtain summary judgment on such a claim (assuming that there is no good defence to it). Recognition and enforcement of a US judgment by a Jersey court in such an action is conditional upon (among other things) the following: • the US court having had jurisdiction over the original proceedings according to Jersey conflicts of laws principles; • the US judgment being final and conclusive on the merits in the sense of being final and unalterable in the court which pronounced it and being for a definite sum of money (although there are circumstances where non-money judgments can also be enforced); • the US judgment not contravening Jersey public policy; • the US judgment not being for a sum payable in respect of taxes, or other charges of a like nature, or in respect of a penalty or fine; • the US judgment not having been arrived at by doubling, trebling or otherwise multiplying a sum assessed as compensation for the loss or damages sustained and not being otherwise in breach of Section 5 of the United Kingdom Protection of Trading Interests Act 1980 (as extended to Jersey by the Protection of Trading Interests Act 1980 (Jersey) Order 1983); • the US judgment not having been obtained by fraud or in breach of Jersey principles of natural justice; and • there not having been a prior inconsistent decision of a Jersey court in respect of the same matter. Subject to the foregoing, investors may be able to enforce in Jersey judgments in civil and commercial matters that have been obtained from US federal or state courts. However, we cannot assure you that those judgments will be recognised or enforceable in Jersey. In addition, it is questionable whether a Jersey court would accept jurisdiction and impose civil liability if the original action was commenced in Jersey, instead of the United States, and predicated solely upon US federal securities laws. United Arab Emirates The UAE and the Emirate of Sharjah currently do not have a treaty providing for the reciprocal recognition and enforcement of US Federal or state court judgments in civil and commercial matters. Consequently, a final judgment for payment rendered by any federal or state court in the United States based on civil liability, whether or not predicated solely upon US federal securities laws, would not automatically be recognised or enforceable in Sharjah. In order to enforce any such US judgment in Sharjah, proceedings must first be initiated before a court of competent jurisdiction in Sharjah. In such an action, and subject to the comments below, a Sharjah court would enforce the judgment without re-examination of the merits. Recognition and enforcement of a US judgment by a Sharjah court in such an action is conditional upon (among other things) the following: • no court in the UAE has jurisdiction in the dispute and the foreign court did have jurisdiction;

138 • the US judgment is final and enforceable; • the parties in relation to which the judgment was issued had been given due notice of the proceedings and were represented; • the foreign judgment does not conflict with any judgment issued by a court in the UAE and contains nothing that would be in breach of public policy, order or morals of the UAE; and • the US judgment was not obtained by fraud or in breach of principles of natural justice.

In respect of the first factor noted above, potential investors should bear in mind that the concept of concurrent jurisdiction might not be entertained by a Sharjah court. As a result, a Sharjah court might conclude that a US court could not properly have jurisdiction over a dispute that involved a Sharjah party and over which the Sharjah courts would instead have jurisdiction. In addition, a demonstration of reciprocity between the US courts and the Sharjah courts might be required in support of an action for enforcement.

139 LISTING AND GENERAL INFORMATION

Listing The Company was incorporated in Jersey on 10 January 2002. The registered address of the Company is Ogier House, The Esplanade, St Helier, Jersey JE4 9WG.

Application has been made for the Notes to be listed on the Official List of the Irish Stock Exchange and to be traded on the Irish Stock Exchange’s Global Exchange Market, in accordance with the rules of that exchange.

So long as the Notes are listed on the Official List of the Irish Stock Exchange and to be traded on the Irish Stock Exchange’s Global Exchange Market and the rules of such exchange shall so require, copies of our Articles of Association and those of the Guarantors and the Fiscal Agency Agreement will be available in physical form free of charge at the registered address of the Company. The Guarantees will be issued pursuant to the Fiscal and Paying Agency Agreement. So long as the Notes are listed on the Irish Stock Exchange’s Global Exchange Market and the rules of such exchange shall so require, copies of the financial statements included in this Offering Memorandum will be available in physical form free of charge during normal business hours on any weekday at the registered address of the Company.

It is expected that the total expenses relating to the application for admission of the Notes to the Official List and for admission of the Notes to trading on its Global Exchange Market will be approximately US$7,000.

Application may be made to the Global Exchange Market to have the Notes removed from listing on the Global Exchange Market, including if necessary to avoid any new withholding taxes in connection with the listing.

So long as the Notes are listed on the Global Exchange Market, the Notes will be freely transferable and negotiable in accordance with the rules of the Global Exchange Market.

Clearing Information We expect that the global notes sold pursuant to Rule 144A and Regulation S will be accepted for clearance through the facilities of DTC. The ISIN number for the Notes sold pursuant to Regulation S is USG7052TAC56. The ISIN number for the Notes sold pursuant to Rule 144A is US716473AC70. The CUSIP number for the Notes sold pursuant to Regulation S is G7052T AC5. The CUSIP number for the Notes sold pursuant to Rule 144A is 716473 AC7.

Legal Information The Company’s issued share capital is US$7 million, represented by 345,912,747 ordinary shares, each with a nominal value of US$0.02 and on a vote on a resolution on a poll each entitling the holder to one vote. All shares are registered, fully paid. For so long as the Notes are listed on the Global Exchange Market operated by the Irish Stock Exchange, and the rules of that exchange so require, copies of the Company’s organisational documents, the Fiscal and Paying Agency Agreement, the Deed of Covenant and our most recent consolidated financial statements published by us may be inspected and obtained at the registered office of the Company. See “—Listing”. There have been no recent events which are relevant to the evaluation of the Company’s insolvency. There have been no governmental proceedings with respect to the Company.

Offering Memorandum 1. The Company and the Guarantors accept responsibility for the information contained in this Offering Memorandum. To the best of the Company’s and Guarantors’ knowledge, the information contained in this Offering Memorandum is in accordance with the facts and does not omit anything likely to affect the import of this Offering Memorandum. 2. Except as disclosed herein, there has been no material adverse change in our consolidated financial position, our capitalisation or our prospects since 31 December 2012. 3. There has been no significant change in our financial or trading position since 30 June 2013. 4. We have appointed Citibank, N.A., London Branch as our Paying Agent. We reserve the right to vary such appointment and shall publish notice of such change of appointment in a newspaper having general circulation in Ireland (which is expected to be The Irish Times) or on the Irish Stock Exchange’s website, www.ise.ie.

140 5. The issue of the Notes was authorised by resolutions of the Board of Directors of the Company passed at meetings held on 22 February and 11 April 2013. The Board re-affirmed the resolutions at a meeting on 21 August 2013. The Guarantees were authorised by resolutions of the board of directors of Petrofac International Ltd on 15 May 2013 and resolutions of the board of directors of Petrofac International (UAE) LLC on 19 May 2013. The boards of directors of Petrofac International Ltd and Petrofac International (UAE) LLC each re-affirmed their respective resolutions at meetings held on 4 September 2013.

141 GLOSSARY

The following terms (or variations thereof) are used in this Offering Memorandum:

“affiliate” as defined in Rule 144 under the Securities Act

“Agent” Standard Chartered Bank, the agent of the finance parties under the Revolving Credit Facility

“Aker Solutions” Aker Solutions ASA

“AMEC” AMEC plc

“brownfield development” further investment in a mature field, to enhance its production capacity, thereby increasing recovery and extending field life

“Board”or“Board of Directors” the board of directors of Petrofac Limited

“BURRC” Business Unit Risk Review Committees

“CCC” Consolidated Contractors International Company

“CIS” the Commonwealth of Independent States

“Clearstream” Clearstream Banking, S.A.

“Company” Petrofac Limited

“Commission” Jersey Financial Services Commission

“Consolidated Financial Statements” the audited financial statements of the Company and its subsidiaries, associates and joint ventures as of and for the years ended 31 December 2012, 2011 and 2010

“CPECC” China Petroleum Engineering & Construction Corporation

“DoA” Delegations of Authority

“D&O Insurance” Directors and Officers Liability Insurance

“DSME” Daewoo Shipbuilding & Marine Engineering Co Ltd

“DTC” The Depositary Trust Company

“Dyas” Dyas UK Limited

“ECOM” Engineering, Construction, Operations & Maintenance

“ECS” Engineering & Consulting Services

“ECV” Estimated Contract Value

“EEA” European Economic Area

“EPC” engineering, procurement and construction

“EPIC” engineering, procurement, installation and commissioning

“ERM” Enterprise Risk Management

“ETR” effective tax rate

142 “Euroclear” Euroclear Bank, S.A./N.V.

“EU Savings Directive” EC Council Directive 2003/48/EC on the taxation of savings income

“Exchange Act” US Securities Exchange Act of 1934, as amended

“Facilities” the two facilities, Facility A and Facility B, that form the Revolving Credit Facility

“FEED” front-end engineering and design

“Financial Promotion Order” the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended

“Financial Statements” the 2013 Interim Condensed Consolidated Financial Information together with the Consolidated Financial Statements

“Fiscal Agent” Citibank, N.A., London Branch

“FPSO” floating production, storage and offloading vessel

“FSMA” Financial Services and Markets Act 2000

“GRI” Global Reporting Initiative

“greenfield development” development of a new field

“Group” Petrofac Limited and its subsidiaries

“GRC” Group Risk Committee

“Guarantees” the irrevocable and unconditional guarantees of the Guarantors for the due and prompt payment of all amounts at any time becoming due and payable in respect of each of the Notes under the deeds of guarantee

“Guarantors” Petrofac International Ltd and Petrofac International (UAE) LLC

“HMRC” Her Majesty’s Revenue and Customs

“HSE” UK Health and Safety Executive

“IEA” International Energy Agency

“IES” Integrated Energy Services

“IFRS” International Financial Reporting Standards as issued by the International Accounting Standards Board

“Independent Auditors” Ernst & Young LLP

“IOC” international oil company

“Initial Purchasers” Barclays Capital Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBS Securities Inc.

“Investor’s Currency” an investor’s financial activities that are denominated in a currency unit other than the US dollar

“Issue Date” 2013

“Ithaca” Ithaca Energy (UK) Limited

143 “JCE” jointly-controlled entity

“Jersey Registrar” registrar of companies in Jersey

“IPCI” integrated petrochemicals complex and infrastructure

“IRS” Internal Revenue Service

“IT” information technology

“KOC” Kuwait Oil Company

“KPI” key performance indicator

“LPG” liquefied petroleum gas

“Member State” a member state of the European Economic Area

“Moody’s” Moody’s Investors Service Ltd

“MOU” memorandum of understanding

“Nama Project Services” Nama Project Services LLC, an affiliate of Nama Development Enterprises

“Net Cash / (Debt)” Comprises cash and short-term deposits, bank overdrafts, interesting bearing loans and borrowings (including the amounts utilised under our Revolving Credit Facility and project financing debt), adjusted to exclude unamortised debt acquisition costs and effective interest rate adjustments.

“NGL” natural gas liquids

“NOCs” national oil companies

“Notes” an aggregate principal amount of US$750,000,000 3.400% Senior Notes due 2018

“Obligors” the RCF Borrowers and RCF guarantors

“OCP” Offshore Capital Projects

“OEC” Onshore Engineering & Construction

“Offering” the offering by the Company of an aggregate principal amount of US$750,000,000 3.400% Senior Notes due 2018

“Official List” the Official List of the ISE

“OPO” Offshore Projects & Operations

“OSHA” Occupational Safety and Health Administration

“Paying Agent” Citibank, N.A., London Branch

“PEC” production enhancement contract

“Petrofac Emirates” Petrofac Emirates LLC

“Pemex” Petróleos Mexicanos

144 “Petronas” Petroliam Nasional Berhad

“Prospectus Directive” Directive (2003/71/EC) (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State) and any relevant implementing measure in each Relevant Member State

“PSC” production sharing contract

“QIBs” qualified institutional buyers, within the meaning of Rule 144A of the Securities Act

“qualified investor” persons who are “qualified investors” within the meaning of Article 2(1)(e) of the Prospectus Directive.

“RCF Borrowers” Petrofac Treasury B.V. and Petrofac International (UAE) LLC, and any additional borrower as may be added under the terms of the Revolving Credit Facility

“RCF Guarantors” Petrofac Limited, Petrofac International Ltd, Petrofac Treasury B.V. and Petrofac International (UAE) LLC, and any additional guarantor as may be added under the terms of the Revolving Credit Facility

“Revolving Credit Facility” the revolving credit facility described in “Operating and Financial Review—Liquidity and Capital Resources—Indebtedness— Revolving Credit Facility”

“Registrar” Citigroup Global Markets Deutschland AG

“Regulation S” Regulation S under the Securities Act

“Relevant Member State” a member state of the European Economic Area which has implemented the Prospectus Directive

“relevant persons” persons who (i) have professional experience in matters relating to investments falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended, (the “Financial Promotion Order”), (ii) are persons falling within Article 49(2)(a) to (d) of the Financial Promotion Order (high net worth companies, unincorporated associations, etc.) or (iii) are persons to whom an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000 (“FSMA”)) in connection with the issue or sale of any Notes

“RNZ” RNZ Integrated Sdn Bhd

“RSC” risk service contract

“Rule 144A” Rule 144A under the Securities Act

“Saipem” Saipem S.p.A

“Sarb 3” Satah Al Razboot package 3

“Saudi Aramco” Saudi Arabian Oil Company

“SEC” United States Securities and Exchange Commission

“Securities Act” United States Securities Act of 1933, as amended

“Securities” the Notes and the Guarantees

145 “Senior Management” those members of the Senior Management of Petrofac Limited named in this Offering Memorandum

“Seven Energy” Seven Energy International Limited

“SURF” subsea, umbilicals, risers and flowlines

“S&P” Standard & Poor’s Financial Services LLC, a division of The McGraw-Hill Companies, Inc.

“Stabilising Managers” Barclays Capital Inc. and J.P. Morgan Securities LLC

“Subsea 7” Subsea S.A.

“Technip” Technip S.A.

“Transfer Agent” Citibank, N.A., London Branch

“Wood Group” John Wood Group plc

“UKCS” United Kingdom Continental Shelf

“United States”or“US” the United States of America, its territories and possessions, any State of the United States of America, and the District of Columbia

“US Exchange Act” United States Securities Exchange Act of 1934, as amended

“2013 Interim Condensed Consolidated Financial Statements” the unaudited interim condensed consolidated financial statements of the Company and its subsidiaries, associates and joint ventures as of and for the six months ended 30 June 2013 (including comparative financial information as of and for the six months ended 30 June 2012)

146 INDEX TO FINANCIAL STATEMENTS

Page Unaudited Interim Condensed Consolidated Financial Statements as of and for the Six Months Ended 30 June 2013 and 2012 Independent review report ...... F-2 Interim condensed consolidated income statement ...... F-3 Interim condensed consolidated statement of comprehensive income ...... F-4 Interim condensed consolidated statement of financial position ...... F-5 Interim condensed consolidated statement of cash flows ...... F-6 Interim condensed consolidated statement of changes in equity ...... F-7 Notes to the Interim condensed consolidated financial statements ...... F-8 Audited Consolidated Financial Statements as of and for the Years Ended 31 December 2012 and 2011 Independent auditor’s report ...... F-24 Consolidated income statement ...... F-26 Consolidated statement of comprehensive income ...... F-27 Consolidated statement of financial position ...... F-28 Consolidated statement of cash flows ...... F-29 Consolidated statement of changes in equity ...... F-30 Notes ...... F-31 Audited Consolidated Financial Statements as of and for the Years Ended 31 December 2011 and 2010 Independent auditor’s report ...... F-80 Consolidated income statement ...... F-82 Consolidated statement of comprehensive income ...... F-83 Consolidated statement of financial position ...... F-84 Consolidated statement of cash flows ...... F-85 Consolidated statement of changes in equity ...... F-86 Notes ...... F-87 Audited Consolidated Financial Statements as of and for the Years Ended 31 December 2010 and 2009 Independent auditor’s report ...... F-141 Consolidated income statement ...... F-143 Consolidated statement of comprehensive income ...... F-144 Consolidated statement of financial position ...... F-145 Consolidated statement of cash flows ...... F-146 Consolidated statement of changes in equity ...... F-147 Notes ...... F-149

F-1 Independent review report to Petrofac Limited Introduction We have been engaged by Petrofac Limited (‘the Company’) to review the interim condensed consolidated financial statements in the interim report for the six months ended 30 June 2013 which comprises the interim condensed consolidated income statement, the interim condensed consolidated statement of comprehensive income, the interim condensed consolidated statement of financial position, the interim condensed consolidated cash flow statement, the interim condensed consolidated statement of changes in equity and the related explanatory notes. We have read the other information contained in the interim report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim condensed consolidated financial statements.

This report is made solely to the company in accordance with guidance contained in International Standard on Review Engagements 2410 (UK and Ireland) “Review of Interim Financial Information Performed by the Independent Auditor of the Entity” issued by the Auditing Practices Board. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our work, for this report, or for the conclusions we have formed.

Directors’ responsibilities The interim report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the interim report in accordance with the Disclosure and Transparency Rules of the United Kingdom’s Financial Conduct Authority.

As disclosed in note 2, the annual financial statements of the group are prepared in accordance with IFRS. The interim condensed consolidated financial statements included in this interim report have been prepared in accordance with International Accounting Standard 34, “Interim Financial Reporting”.

Our responsibility Our responsibility is to express to the Company a conclusion on the interim condensed consolidated financial statements in the interim report based on our review.

Scope of review We conducted our review in accordance with International Standard on Review Engagements 2410 (UK and Ireland), “Review of Interim Financial Information Performed by the Independent Auditor of the Entity” issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion Based on our review, nothing has come to our attention that causes us to believe that the interim condensed consolidated financial statements in the interim report for the six months ended 30 June 2013 are not prepared, in all material respects, in accordance with International Accounting Standard 34 and the Disclosure and Transparency Rules of the United Kingdom’s Financial Conduct Authority.

Ernst & Young LLP London 23 August 2013

F-2 Interim condensed consolidated income statement For the six months ended 30 June 2013

Six months Six months ended Year ended ended 30 June 31 December 30 June 2012 2012 2013 Unaudited Audited Unaudited US$m US$m Notes US$m (Restated) (Restated) Revenue ...... 4 2,794 3,187 6,240 Cost of sales ...... (2,292) (2,655) (5,164) Gross profit ...... 502 532 1,076 Selling, general and administration expenses ...... 5 (217) (176) (357) Other income ...... 6 8 46 65 Other expenses ...... (8) (9) (20) Profit from operations before tax and finance (costs)/income ... 285 393 764 Finance costs ...... (6) (2) (5) Finance income ...... 11 312 Share of profits/(losses) of associates/joint ventures ...... 14 10 19 (6) Profit before tax ...... 300 413 765 Income tax expense ...... 7 (58) (89) (135) Profit for the period ...... 242 324 630 Attributable to: Petrofac Limited shareholders ...... 243 326 632 Non-controlling interests ...... (1) (2) (2) 242 324 630 Earnings per share (US cents) ...... 8 – Basic ...... 71.24 95.55 185.55 – Diluted ...... 70.72 94.82 183.88

The attached notes 1 to 22 form part of these interim condensed consolidated financial statements.

F-3 Interim condensed consolidated statement of comprehensive income For the six months ended 30 June 2013

Six months Six months ended ended Year ended 30 June 30 June 31 December 2013 2012 2012 Unaudited Unaudited Audited Notes US$m US$m US$m Profit for the period ...... 242 324 630 Other Comprehensive Income Foreign currency translation (losses)/gains ...... 18 (27) (3) 10 Net loss on cash flow hedges recycled in the period ...... 18 1 12 20 Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... 18 (3) (11) — Other comprehensive income to be reclassified to consolidated income statement in subsequent periods ...... (29) (2) 30 Total comprehensive income for the period ...... 213 322 660 Attributable to: Petrofac Limited shareholders ...... 214 324 662 Non-controlling interests ...... (1) (2) (2) 213 322 660

The attached notes 1 to 22 form part of these interim condensed consolidated financial statements.

F-4 Interim condensed consolidated statement of financial position At 30 June 2013

30 June 31 December 30 June 2012 2012 2013 Unaudited Audited Unaudited US$m US$m Notes US$m (Restated) (Restated) ASSETS Non-current assets Property, plant and equipment ...... 10 907 664 897 Goodwill ...... 12 147 120 125 Intangible assets ...... 13 358 178 307 Investments in associates / joint ventures ...... 14 199 226 210 Other financial assets ...... 15 530 334 444 Deferred income tax assets ...... 48 33 43 2,189 1,555 2,026 Current assets Inventories ...... 38 22 27 Work in progress ...... 742 964 656 Trade and other receivables ...... 1,975 1,297 1,846 Due from related parties ...... 21 29 10 10 Other financial assets ...... 15 171 20 85 Income tax receivable ...... 6 912 Cash and short-term deposits ...... 16 538 790 582 3,499 3,112 3,218 TOTAL ASSETS ...... 5,688 4,667 5,244 EQUITY AND LIABILITIES Equity attributable to Petrofac Limited shareholders Share capital ...... 7 77 Share premium ...... 4 44 Capital redemption reserve ...... 11 11 11 Treasury shares ...... 17 (114) (105) (100) Other reserves ...... 18 9 (3) 38 Retained earnings ...... 1,683 1,355 1,589 1,600 1,269 1,549 Non-controlling interests ...... 5 11 TOTAL EQUITY ...... 1,605 1,270 1,550 Non-current liabilities Interest-bearing loans and borrowings ...... 19 835 2 292 Provisions ...... 106 70 100 Other financial liabilities ...... 15 6 13 8 Deferred income tax liabilities ...... 102 97 143 1,049 182 543 Current liabilities Trade and other payables ...... 1,927 1,669 1,918 Due to related parties ...... 21 1 58 34 Interest-bearing loans and borrowings ...... 19 73 65 57 Other financial liabilities ...... 15 19 22 17 Income tax payable ...... 138 99 75 Billings in excess of cost and estimated earnings ...... 365 274 307 Accrued contract expenses ...... 511 1,028 743 3,034 3,215 3,151 TOTAL LIABILITIES ...... 4,083 3,397 3,694 TOTAL EQUITY AND LIABILITIES ...... 5,688 4,667 5,244

The attached notes 1 to 22 form part of these interim condensed consolidated financial statements.

F-5 Interim condensed consolidated statement of cash flows For the six months ended 30 June 2013

Six months Six months ended Year ended ended 30 June 31 December 30 June 2012 2012 2013 Unaudited Audited Unaudited US$m US$m Notes US$m (Restated) (Restated) OPERATING ACTIVITIES Profit before tax ...... 300 413 765 Non-cash adjustments to reconcile profit before tax to net cash flows: Depreciation, amortisation, impairment and write off ...... 110 43 130 Share-based payments ...... 17 7 13 26 Difference between other long-term employment benefits paid and amounts recognised in the income statement ...... 4 911 Net finance income ...... (5) (1) (7) Gain arising from sale of a vessel under a finance lease ...... 3 (22) —— Gain on disposal of non-current asset held for sale ...... 6 — (27) (27) Gain on disposal of an investment in a joint venture ...... — — (6) Fair value gain on initial recognition of investment in associate ...... — (9) (9) Loss on fair value changes in Seven Energy warrants ...... — 46 Share of (profits)/losses of associates / joint ventures ...... (10) (19) 6 Debt acquisition costs write off ...... — —3 Other non-cash items, net ...... 4 47 Operating profit before working capital changes ...... 388 430 905 Trade and other receivables ...... 160 55 (487) Work in progress ...... (86) (384) (44) Due from related parties ...... (18) 89 77 Inventories ...... (11) (12) (16) Other current financial assets ...... 42 (1) (68) Trade and other payables ...... (325) (49) 184 Billings in excess of cost and estimated earnings ...... 19 (115) (82) Accrued contract expenses ...... (233) (205) (525) Due to related parties ...... (33) 35 11 Other current financial liabilities ...... — (1) — (97) (158) (45) Long-term receivable from customers ...... (76) (204) (300) Other non-current items, net ...... 6 3 (4) Cash used in operations ...... (167) (359) (349) Interest paid ...... (5) — (3) Income taxes paid, net ...... (37) (42) (83) Net cash flows used in operating activities ...... (209) (401) (435) INVESTING ACTIVITIES Purchase of property, plant and equipment ...... 10 (201) (149) (397) Acquisition of subsidiaries, net of cash acquired ...... 62 (15) (20) Payment of deferred consideration on acquisition ...... — — (1) Purchase of other intangible assets ...... (16) — (7) Purchase of intangible oil & gas assets ...... (44) (54) (165) Investments in associates ...... — — (25) Dividend received from a joint venture ...... 2 —2 Proceeds from disposal of property, plant and equipment ...... — —1 Proceeds from disposal of non-current asset held for sale ...... — 60 60 Proceeds from disposal of an investment in a joint venture ...... — —5 Interest received ...... 1 35 Net cash flows used in investing activities ...... (196) (155) (542) FINANCING ACTIVITIES Interest-bearing loans and borrowings obtained, net of debt ...... acquisition cost ...... 568 — 291 Repayment of interest-bearing loans and borrowings ...... (9) (11) (50) Treasury shares purchased ...... 17 (45) (76) (76) Equity dividends paid ...... (148) (128) (201) Net cash flows from/(used in) financing activities ...... 366 (215) (36) NET DECREASE IN CASH AND CASH EQUIVALENTS ...... (39) (771) (1,013) Net foreign exchange difference ...... (1) (11) 3 Cash and cash equivalents at 1 January ...... 525 1,535 1,535 CASH AND CASH EQUIVALENTS AT PERIOD END ...... 16 485 753 525

The attached notes 1 to 22 form part of these interim condensed consolidated financial statements.

F-6 Interim condensed consolidated statement of changes in equity For the six months ended 30 June 2013

Attributable to Petrofac Limited Shareholders Issued Capital *Treasury Other Non- share Share redemption shares reserves Retained controlling Total capital premium reserve US$m US$m Earnings Total interests equity US$m US$m US$m (note 17) (note 18) US$m US$m US$m US$m For the six months ended 30 June 2013 Balance at 1 January 2013 ...... 7 4 11 (100) 38 1,589 1,549 1 1,550 Profit for the period ...... — — — — — 243 243 (1) 242 Other comprehensive income ...... — — — — (29) — (29) — (29) Total comprehensive income ...... — — — — (29) 243 214 (1) 213 Treasury shares purchased (note 17) ...... — — — (45) — — (45) — (45) Share-based payments charge (note 17) ...... — — — — 7 — 7 — 7 Transfer to reserve for share-based payments (note 17) ...... — — — — 22 — 22 — 22 Shares vested during the period (note 18) ...... — — — 31 (29) (2) — — — Income tax on share-based payments reserve . . . — — — — — — — — — Dividends (note 9) ...... — — — — — (147) (147) — (147) Non-controlling interest arising on a business combination (note 11) ...... — — — — — — — 5 5 Balance at 30 June 2013 (unaudited) ...... 7 4 11 (114) 9 1,683 1,600 5 1,605

Attributable to Petrofac Limited Shareholders Issued Capital *Treasury Other Non- share Share redemption shares reserves Retained controlling Total capital premium reserve US$m US$m Earnings Total interests Equity US$m US$m US$m (note 17) (note 18) US$m US$m US$m US$m For the six months ended 30 June 2012 Balance at 1 January 2012 ...... 7 2 11 (75) 6 1,161 1,112 3 1,115 Profit for the period ...... — — — — — 326 326 (2) 324 Other comprehensive income ...... — — — — (2) — (2) — (2) Total comprehensive income ...... — — — — (2) 326 324 (2) 322 Shares issued as payment of consideration on acquisition ...... — 2 — — — — 2 — 2 Treasury shares purchased (note 17) ...... — — — (76) — — (76) — (76) Share-based payments charge (note 17) ...... — — — — 13 — 13 — 13 Transfer to reserve for share-based payments (note 17) ...... — — — — 20 — 20 — 20 Shares vested during the period (note 18) ...... — — — 46 (41) (5) — — — Income tax on share-based payments reserve . . . — — — — 1 — 1 — 1 Dividends (note 9) ...... — — — — — (127) (127) — (127) Balance at 30 June 2012 (unaudited) ...... 7 4 11 (105) (3) 1,355 1,269 1 1,270

Attributable to Petrofac Limited Shareholders Issued Capital *Treasury Other Non- share Share redemption shares reserves Retained controlling Total capital premium reserve US$m US$m Earnings Total interests equity US$m US$m US$m (note 17) (note 18) US$m US$m US$m US$m For the year ended 31 December 2012 Balance at 1 January 2012 ...... 7 2 11 (75) 6 1,161 1,112 3 1,115 Profit for the year ...... — — — — — 632 632 (2) 630 Other comprehensive income ...... — — — — 30 — 30 — 30 Total comprehensive income ...... — — — — 30 632 662 (2) 660 Shares issued as payment of deferred consideration on acquisition ...... — 2 — — — — 2 — 2 Treasury shares purchased (note 17) ...... — — — (76) — — (76) — (76) Share-based payments charge (note 17) ...... — — — — 26 — 26 — 26 Transfer to reserve for share-based ...... payments (note 17) ...... — — — — 20 — 20 — 20 Shares vested during the year (note 18) ...... — — — 51 (45) (6) — — — Income tax on share-based payments reserve . . . — — — — 1 — 1 — 1 Dividends (note 9) ...... — — — — — (198) (198) — (198) Balance at 31 December 2012 (audited) ...... 7 4 11 (100) 38 1,589 1,549 1 1,550

*Shares held by Petrofac Employee Benefit Trust and Petrofac Joint Venture Companies Employee Benefit Trust

The attached notes 1 to 22 form part of these interim condensed consolidated financial statements.

F-7 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

1 Corporate information Petrofac Limited is a limited liability company registered and domiciled in Jersey under the Companies (Jersey) Law 1991 and is the holding company for the international group of Petrofac subsidiaries (together “the Group”). The Group’s principal activity is the provision of services to the oil & gas production and processing industry. The interim condensed consolidated financial statements of the Group for the six months ended 30 June 2013 were authorised for issue in accordance with a resolution of the Board of Directors on 23 August 2013.

2 Basis of preparation and accounting policies Basis of preparation The interim condensed consolidated financial statements have been prepared on a historical cost basis, except for derivative financial instruments that have been measured at fair value. The presentation currency of the interim condensed consolidated financial statements is United States dollars (US$) and all values in the interim condensed consolidated financial statements are rounded to the nearest million (US$m) except where otherwise stated.

Statement of compliance The interim condensed consolidated financial statements of Petrofac Limited and all its subsidiaries for the six months ended 30 June 2013 have been prepared in accordance with IAS 34 ‘Interim Financial Statements’ and applicable requirements of Jersey law. They do not include all of the information and disclosures required in the annual financial statements and should be read in conjunction with the consolidated financial statements of the Group as at and for the year ended 31 December 2012. Certain comparative information has been restated in the current period presentation as outlined below.

Restatements The following restatements were made in the 2012 comparatives: • The financial performance of the Group for the period ended 30 June 2012 and for the year ended 31 December 2012 and the financial position of the Group as at 30 June 2012 and as at 31 December 2012 have been restated by replacing proportionate consolidation of joint ventures (Petrofac Emirates LLC, TTE Petrofac Limited, Professional Mechanical Repair Services Company, Spie Capag – Petrofac International Limited and China Petroleum Petrofac Engineering Services Cooperatif U.A.) with the equity method of accounting, as a result of the application of new IFRS 11 – Joint Arrangements and amended IAS 28 – Investment in associates and joint ventures (see note 14 for details).

Accounting policies The accounting policies and methods of computation adopted in the preparation of these interim condensed consolidated financial statements are consistent with those followed in the preparation of the Group’s annual financial statements for the year ended 31 December 2012, except for the adoption of new standards and interpretations effective as of 1 January 2013.

The Group has adopted new and revised Standards and Interpretations issued by the International Accounting Standards Board (IASB) and the International Financial Reporting Interpretations Committee (IFRIC) of the IASB that are relevant to its operations and effective for accounting periods beginning on or after 1 January 2013.

The principal effects of the adoption of the relevant new and amended standards and interpretations are discussed below:

IAS 1 – Presentation of Items of Other Comprehensive Income (Amendment) The amendments to IAS 1 introduce a grouping of items presented in other comprehensive income (OCI). Items that could be recycled to the consolidated income statement at a future point in time now have to be presented separately from items that will never be recycled. The amendment only affected the presentation and had no impact on the Group’s financial position or performance.

F-8 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

2 Basis of preparation and accounting policies (continued)

IAS 34 – Interim financial reporting and segment information for total assets and liabilities (Amendment) The amendment clarifies the requirements in IAS 34 relating to segment information for total assets and liabilities for each reportable segment to enhance consistency with the requirements in IFRS 8 Operating Segments. Total assets and liabilities for a reportable segment need to be disclosed only when the amounts are regularly provided to the chief operating decision maker. The Group does not present this information to the chief operating decision maker. Accordingly, the Group has not made such disclosures.

IFRS 10 – Consolidated Financial Statements and IAS 27 – Separate Financial Statements IFRS 10 establishes a single control model that applies to all entities including special purpose entities. IFRS 10 replaces the parts of the previously existing IAS 27 Consolidated and Separate Financial Statements that dealt with consolidated financial statements and SIC 12 Consolidation – Special Purpose Entities. IFRS 10 changes the definition of control such that an investor controls an investee when it is exposed, or has rights to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. To meet the definition of control in IFRS 10, all three criteria must be met, including: (a) an investor has power over an investee; (b) the investor has exposure, or rights, to variable returns from its involvement with the investee; and (c) the investor has the ability to use its power over the investee to affect the amount of the investor’s returns. IFRS 10 has had no impact on the consolidation of investments held by the Group.

IFRS 11 – Joint Arrangements and IAS 28 – Investment in Associates and Joint Ventures IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC 13 Jointly-controlled Entities – Non-monetary Contributions by Venturers. IFRS 11 removes the option to account for jointly controlled entities (JCEs) using proportionate consolidation. Instead, JCEs that meet the definition of a joint venture under IFRS 11 must be accounted for using the equity method.

The application of this new standard impacted the financial position of the Group by replacing proportionate consolidation of the joint venture in Petrofac Emirates LLC, TTE Petrofac Limited, Professional Mechanical Repair Services Company, Spie Capag – Petrofac International Limited and China Petroleum Petrofac Engineering Services Cooperatif U.A. with the equity method of accounting. IFRS 11 is effective for annual periods beginning on or after 1 January 2013. The effect of IFRS 11 is described in more detail in note 14, which includes quantification of the effect on the financial statements.

IFRS 12 – Disclosure of Interests in Other Entities IFRS 12 sets out the requirements for disclosures relating to an entity’s interests in subsidiaries, joint arrangements, associates and structured entities. None of these disclosure requirements are applicable for interim condensed consolidated financial statements. Accordingly, the Group has not made such disclosures.

IFRS 13 – Fair Value Measurement IFRS 13 establishes a single source of guidance under IFRS for all fair value measurements. IFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under IFRS when fair value is required or permitted. The application of IFRS 13 has not materially impacted the fair value measurements carried out by the Group. IFRS 13 also requires specific disclosures of fair values and these disclosures are shown in note 22.

F-9 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

3 Segment information The following tables represent revenue and profit information relating to the Group’s four reporting segments for the six months ended 30 June 2013 which comprises:

Onshore Engineering & Construction which provides engineering, procurement and construction project execution services to the onshore oil & gas industry.

Offshore Projects & Operations which provides offshore engineering, operations and maintenance on and offshore and engineering, procurement and construction project execution services to the offshore oil & gas industry.

Engineering & Consulting Services which provides technical engineering, consultancy, conceptual design, front end engineering and design (FEED) and project management consultancy (PMC) across all sectors including renewables and carbon capture.

Integrated Energy Services which co-invests with partners in oil & gas production, processing and transportation assets, provides production improvement services under value aligned commercial structures and oil & gas related technical competency training and consultancy services.

Management separately monitors the trading results of its four reporting segments for the purpose of making an assessment of their performance and making decisions about how resources are allocated to them. Each segment’s performance is measured based on its profitability which is reflected in a manner consistent with the results shown below. However certain shareholder service related overheads, Group financing and consolidation adjustments are managed at corporate level and are not allocated to reporting segments.

Onshore Engineering Consolidation Engineering Offshore & Integrated adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & others eliminations Total US$m US$m US$m US$m US$m US$m US$m Six months ended 30 June 2013 (unaudited) Revenue External sales ...... 1,610 653 93 415 — 123 2,794 Inter-segment sales ...... — 17 87 4 — (108) — Total revenue ...... 1,610 670 180 419 — (85) 2,794 Segment results ...... 189 20 4 50 — 227 290 Unallocated corporate costs ...... — — — — (5) — (5) Profit / (loss) before tax and finance income / (costs) ...... 189 20 4 50 (5) 27 285 Share of profits of associates/joint ventures ...... 1 — 2 7 — — 10 Finance costs ...... — (1) — (3) (10) 8 (6) Finance income ...... 7 — — 10 10 (16) 11 Profit / (loss) before income tax ...... 197 19 6 64 (5) 19 300 Income tax (expense) ...... (26) (7) (1) (21) (3) — (58) Non-controlling interests ...... — — 1 — — — 1 Profit / (loss) for the period attributable to Petrofac Limited shareholders ...... 171 12 6 43 (8) 19 243 Other segment information Depreciation, amortisation and write- offs ...... 34 9 3 59 6 (1) 110 Other long-term employment benefits ...... 8 1 — — — — 9 Share-based payments ...... 4 1 1 1 — — 7

1 Positive elimination of external sales shown above of US$23m represents a Group adjustment to the overall project percentage of completion on the Laggan Tormore project as OEC and OPO are reflecting in their segments progress on their own respective shares of the total project scope. 2 Includes US$22m gain arising from the granting of a finance lease for the FPF5 vessel to the PM304 joint venture in which the Group has a 30% interest.

F-10 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

3 Segment information (continued)

Onshore Engineering Consolidation Engineering Offshore & Integrated adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & others eliminations Total US$m US$m US$m US$m US$m US$m US$m (Restated) (Restated) (Restated) (Restated) (Restated) (Restated) (Restated) Six months ended 30 June 2012 (unaudited) Revenue External sales ...... 2,317 546 41 314 — 1(31) 3,187 Inter-segment sales ...... 16 115 62 4 — (197) — Total revenue ...... 2,333 661 103 318 — (228) 3,187 Segment results ...... 278 42 4 92 — 2(19) 397 Unallocated corporate costs ...... — — — — (4) — (4) Profit / (loss) before tax and finance income / (costs) ...... 278 42 4 92 (4) (19) 393 Share of profits/(losses) of associates/joint ventures ...... 21 — — (2) — — 19 Finance costs ...... — — — (2) (2) 2 (2) Finance income ...... 4 — — — 3 (4) 3 Profit / (loss) before income tax ...... 303 42 4 88 (3) (21) 413 Income tax (expense) ...... (52) (11) (1) (24) (1) — (89) Non-controlling interests ...... — — 2 — — — 2 Profit / (loss) for the period attributable to Petrofac Limited shareholders ...... 251 31 5 64 (4) (21) 326 Other segment information Depreciation, amortisation and write-offs ..... 19 2 3 20 — (1) 43 Other long-term employment benefits ...... 9 — — — — — 9 Share-based payments ...... 6 1 1 3 2 — 13

1 Elimination of external sales shown above of US$31m represents a Group adjustment to the overall project percentage of completion on the Laggan Tormore project as OEC and OPO are reflecting in their segments progress on their own respective shares of the total project scope. 2 Includes US$19m elimination on consolidation of profit made by OPO on the upgrade of the FPF5 vessel, the costs of which have been capitalised in the property, plant and equipment of IES.

Onshore Engineering Consolidation Engineering Offshore & Integrated adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & others eliminations Total US$m US$m US$m US$m US$m US$m US$m (Restated) (Restated) (Restated) (Restated) (Restated) (Restated) (Restated) Year ended 31 December 2012 (audited) Revenue External sales ...... 4,262 1,237 97 693 — 1(49) 6,240 Inter-segment sales ...... 26 166 148 15 — (355) — Total revenue ...... 4,288 1,403 245 708 — (404) 6,240 Segment results ...... 540 80 30 138 6 2(26) 768 Unallocated corporate costs ...... — — — — (4) — (4) Profit / (loss) before tax and finance income / (costs) ...... 540 80 30 138 2 (26) 764 Share of losses of associates / joint ventures . . . — (1) — (5) — — (6) Finance costs ...... — — — (4) (6) 5 (5) Finance income ...... 8 — 1 7 9 (13) 12 Profit / (loss) before income tax ...... 548 79 31 136 5 (34) 765 Income tax (expense) / benefit ...... (69) (18) (4) (47) 8 (5) (135) Non-controlling interests ...... — — 2 — — — 2 Profit / (loss) for the year attributable to Petrofac Limited shareholders ...... 479 61 29 89 13 (39) 632 Other segment information Depreciation and amortisation ...... 40 16 6 63 7 (2) 130 Other long-term employment benefits ...... 16 1 — 1 — 1 19 Share-based payments ...... 13 3 1 5 4 — 26

1 Elimination of external sales shown above of US$49m represents a Group adjustment to the overall project percentage of completion on the Laggan Tormore project as OEC and OPO are reflecting in their segments progress on their own respective shares of the total project scope. 2 Includes US$31m elimination on consolidation of profit made by OPO on the upgrade of the FPF5 vessel, the costs of which have been capitalised in the property, plant and equipment of IES.

F-11 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

4 Revenues

Six months Six months ended Year ended ended 30 June 31 December 30 June 2012 2012 2013 Unaudited Audited Unaudited US$m US$m US$m (Restated) (Restated) Rendering of services ...... 2,728 3,127 6,121 Sale of crude oil & gas ...... 66 55 111 Sale of processed hydrocarbons ...... — 58 2,794 3,187 6,240

Included in revenues from rendering of services are Offshore Projects & Operations, Engineering & Consulting Services, and Integrated Energy Services revenues of a “pass-through” nature with zero or low margins amounting to US$258m (six months ended 30 June 2012: US$121m; year ended 31 December 2012: US$220m).

5 Selling, general and administration costs The US$41m increase in selling, general and administration costs compared with the equivalent prior year period is principally due to an increase in new project proposal costs of US$11m and increase in staff costs of US$12m relating to new acquisitions during the period.

6 Other income Other income included in comparative periods includes a gain of US$36m which comprises a US$27m gain on disposal of 75.2% of Petrofac’s interest in Petrofac FPF1 Limited to Ithaca Energy Inc and a US$9m increase in the fair value of the remaining 24.8% interest held which is classified as an associate.

7 Income tax Income tax expense is recognised based on management’s best estimate of the income tax rate applicable to the pre-tax income of the interim period.

The major components of the income tax expense are as follows:

Six months Six months ended ended Year ended 30 June 30 June 31 December 2013 2012 2012 Unaudited Unaudited Audited US$m US$m US$m Current income tax Current income tax charge ...... 109 55 97 Adjustments in respect of current income tax of previous periods ...... — (1) (29) Deferred income tax Relating to origination and reversal of temporary differences ...... (50) 35 73 Recognition of tax losses relating to prior periods ...... (1) — (6) 58 89 135

The Group’s effective tax rate for the six months is 19.1% (six months ended 30 June 2012: 21.5%; year ended 31 December 2012: 17.7%).

The Group’s effective tax rate is dependent upon a numbers of factors including the timing of profit recognition between the first and second halves of the year on contracts held as well as mix of jurisdiction in which new contracts are won within the Onshore Engineering & Construction and the Integrated Energy Services segments.

If the consequences of the timing issues noted above are accounted for, the Group’s effective tax rate for year end 2013 is expected to be broadly in line with last year’s effective tax rate.

F-12 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

7 Income tax (continued)

In March 2013, the UK Government announced its intention to accelerate the reduction in the UK corporation tax rate. The tax rate of 23% is from 1 April 2013, 21% from 1 April 2014 and 20% from 1 April 2015. At 30 June 2013 the 23% tax rate change was substantively enacted and the deferred tax assets and liabilities are based on the new rate. The deferred tax assets and liabilities would have reduced by approximately US$3,254,000 and US$116,000 respectively had the further reductions in the corporation tax rates referred to above been substantively enacted as of the said date.

8 Earnings per share Basic earnings per share amounts are calculated by dividing the net profit for the period attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period.

Diluted earnings per share amounts are calculated by dividing the net profit attributable to ordinary shareholders, after adjusting for any dilutive effect, by the weighted average number of ordinary shares outstanding during the period, adjusted for the effects of ordinary shares granted under the employee share award schemes which are held in trust.

The following reflects the income and share data used in calculating basic and diluted earnings per share:

Six months Six months ended ended Year ended 30 June 30 June 31 December 2013 2012 2012 Unaudited Unaudited Audited US$m US$m US$m Net profit attributable to ordinary shareholders for basic and diluted earnings per share ...... 243 326 632

30 June 30 June 31 December 2013 2012 2012 Unaudited Unaudited Audited Number’m Number’m Number’m Weighted average number of ordinary shares for basic earnings per share . . 341 340 340 Effect of diluted potential ordinary shares granted under share-based payment schemes ...... 3 33 Adjusted weighted average number of ordinary shares for diluted earnings per share ...... 344 343 343

9 Dividends paid and proposed Six months Six months ended ended Year ended 30 June 30 June 31 December 2013 2012 2012 Unaudited Unaudited Audited US$m US$m US$m Declared and paid during the period Equity dividends on ordinary shares: Final dividend for 2011: 37.20 cents per share ...... — 127 127 Interim dividend 2012: 21.00 cents per share ...... — —71 Final dividend for 2012: 43.00 cents per share ...... 147 —— 147 127 198

The Company proposes an interim dividend of 22.00 cents per share which was approved by the Board on 23 August 2013 for payment on 18 October 2013.

F-13 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

10 Property, plant and equipment The increase in property, plant and equipment during the period mainly comprises the expenditure of US$141m in respect of oil & gas assets on the Ticleni Romania and the Magallanes/Santuario/Panuco Mexico Production Enhancement Contracts and additions to temporary facilities and office furniture and equipment on OEC projects of US$27m. This increase is partly offset by depreciation charged during the period of US$103m and sale under a finance lease of a floating platform to a customer with a net book value of US$110m.

11 Business combination Petrofac Emirates LLC (PE) The financial position and performance of PE have been consolidated into the group financial statements from 1 January 2013, the effective date of the acquisition of an additional 25% economic interest by the Group, following the disposal of the 50% economic interest in the entity previously held by Mubadala Petroleum (Mubadala). Nama Development Enterprises has acquired the remaining 25% economic interest. Mubadala ceded control of PE to the Group with effect from 1 January 2013, including the exercise of their voting rights to enable the Group to exercise control over PE. The consideration payable by Petrofac in relation to the acquisition is US$35m, which is included within trade and other payables. This amount will be paid once conditions precedent to legal completion of the transaction have been satisfied.

The fair values of the identifiable assets and liabilities of PE on 1 January 2013 are analysed below:

Recognised on Carrying acquisition value US$m US$m Property, plant and equipment ...... 15 15 Trade and other receivables ...... 258 258 Cash and short term deposits ...... 58 58 331 331 Less: Trade and other payables ...... 269 269 Billings in excess of cost and estimated earnings ...... 39 39 Accrued contract expenses ...... 1 1 309 309 Fair value of net assets acquired ...... 22 Non-controlling interest arising on acquisition ...... (5) Acquisition date fair value of initial 50% interest (note 14) ...... (11) Goodwill arising on acquisition ...... 29 Consideration for 25% interest acquired on 1 January 2013 ...... 35

US$m Cash inflow on acquisition: Cash acquired with subsidiary ...... 58 Net cash inflow on the acquisition of subsidiary ...... 58

The residual goodwill above comprises the fair value of expected future synergies and business opportunities arising from the integration of the business into the group.

RNZ Integrated Sdn Bhd (RNZ) During 2011, the Group entered into a collaboration agreement with the owners of RNZ, whereby, it was agreed that when certain conditions had been fulfilled, three out of five members of the management committee of RNZ would be Petrofac representatives and the actions of the management committee would be decided by a simple majority. The conditions were fulfilled and the membership changes of the management committee took place on 1 April 2013, being the date from which the Group has the power to control the relevant activities of RNZ. RNZ has been consolidated 100% in the Group results since 1 April 2013.

F-14 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

11 Business combination (continued)

If the above combination had taken place at the beginning of the year, net profit of RNZ would have been US$535,000 and revenue would have been US$20m.

12 Goodwill The increase in the goodwill balance in the current period is largely attributable to goodwill of US$29m recognised on the acquisition of an additional 25% interest in Petrofac Emirates LLC. The previously held interest in Petrofac Emirates LLC was classified as an investment in a joint venture (note 14). This increase is partly offset by a negative foreign exchange movement of US$7m.

13 Intangible assets The increase in intangible assets during the period comprises largely of US$37m of capitalised expenditure on the Group’s assets in Malaysia and well development costs of US$15m in respect of Production Enhancement Contracts in Mexico.

14 Investments in associates / joint ventures The movement in investments in associates and investments in joint ventures during the period is as follows:

Joint Associates ventures Total US$m US$m US$m As at 1 January 2013 (restated) ...... 189 21 210 Share of profits in associates / joint ventures ...... 5 5 10 Transferred to investment in subsidiary ...... — (11) (11) Dividends received/receivable ...... — (10) (10) 194 5 199

Interest in a joint venture (transition to IFRS 11) Under IAS 31 Investment in Joint Ventures (prior to the transition to IFRS 11), the Group’s interest in Petrofac Emirates LLC, TTE Petrofac Limited, Professional Mechanical Repair Services Company, Spie Capag—Petrofac International Limited and China Petroleum Petrofac Engineering Services Cooperatif U.A. were classified as jointly controlled entities and the Group’s share of the assets, liabilities, revenue, income and expenses were proportionately consolidated in the consolidated financial statements. Upon adoption of IFRS 11, the Group has determined its interest in these entities to be joint ventures and they are required to be accounted for using the equity method. The effect of applying IFRS 11 is as follows:

Impact on the consolidated income statement

Six months ended Year ended 30 June 31 December 2012 2012 Unaudited Audited US$m US$m Decrease in the reported revenue ...... (55) (84) Decrease in the cost of sales ...... 33 80 Decrease in gross profit ...... (22) (4) Decrease in selling, general and administration expenses ...... — 2 Decrease in operating profit ...... (22) (2) Increase in share of profits of joint ventures ...... 22 2 Net impact on profit after tax ...... ——

F-15 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

14 Investments in associates / joint ventures (continued)

Impact on the consolidated statement of financial position 30 June 31 December 2012 2012 Unaudited Audited US$m US$m Increase in net investment in joint venture (non-current) ...... 43 21 Decrease in non-current assets ...... (9) (8) Decrease in current assets ...... (156) (101) Decrease in current liabilities ...... 122 88 Net impact on equity ...... ——

Impact on the consolidated statement of cash flows Six months ended Year ended 30 June 31 December 2012 2012 Unaudited Audited US$m US$m Decrease in net cash flows from operating activities ...... (52) (34) Increase in net cash flows used in investing activities ...... — 2 Net decrease in cash and cash equivalents ...... (52) (32)

15 Other financial assets and other financial liabilities 30 June 30 June 31 December 2013 2012 2012 Unaudited Unaudited Audited US$m US$m US$m OTHER FINANCIAL ASSETS Non-Current Long-term receivables from customers ...... 402 334 437 Receivable from a joint venture partner ...... 128 —— Restricted cash ...... — —7 530 334 444 Current Short-term component of receivable from a customer ...... 150 —67 Seven Energy warrants ...... 12 13 12 Restricted cash ...... 7 44 Fair value of derivative instruments ...... 2 32 171 20 85 OTHER FINANCIAL LIABILITIES Non-Current Finance lease creditors ...... 4 96 Contingent consideration payable ...... 1 41 Fair value of derivative instruments ...... 1 —1 6 13 8 Current Contingent consideration payable ...... 7 97 Fair value of derivative instruments ...... 6 53 Finance lease creditors ...... 5 67 Other ...... 1 2— 19 22 17

F-16 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

15 Other financial assets and other financial liabilities (continued)

Receivable from a joint venture partner represents amount receivable from a joint venture partner relating to the lease of a floating platform to a customer.

16 Cash and cash equivalents For the purposes of the interim condensed consolidated cash flow statement, cash and cash equivalents comprise:

30 June 31 December 30 June 2012 2012 2013 Unaudited Audited Unaudited US$m US$m US$m (Restated) (Restated) Cash at bank and in hand ...... 438 390 366 Short-term deposits ...... 100 400 216 Cash and short-term deposits ...... 538 790 582 Bank overdrafts ...... (53) (37) (57) 485 753 525

17 Treasury shares and share-based payments During the period, the Company acquired 2,300,000 (30 June 2012: 3,000,000; 31 December 2012: 3,000,000) of its own shares at a cost of US$45m (30 June 2012: US$76m; 31 December 2012: US$76m) for the purpose of making awards under the Group’s employee share schemes and these shares have been classified in the balance sheet as treasury shares within equity. In addition, during the period 1,914,049 shares (including 145,463 accrued dividend and 8% EnQuest uplift shares) with a cost of US$31m were transferred out of the Employee Benefit Trust on vesting of various employee share scheme awards.

The Group has recognised an expense in the income statement for the period to 30 June 2013 relating to employee share-based incentives of US$7m (six months ended 30 June 2012: US$13m; year ended 31 December 2012: US$26m) which has been transferred to the reserve for share-based payments. This charge covers shares granted in relation to the existing Deferred Bonus, Performance and Restricted Share Plans and the Value Creation Plan. In addition US$22m of the remaining bonus liability accrued for the year ended 31 December 2012 (30 June 2012: US$20m; 31 December 2012: US$20m) which has been voluntarily elected or mandatorily obliged to be settled in shares granted during the period has been transferred to the reserve for share based payments. The reduction in the expense for the period compared with the equivalent period in the prior year is due to a significant decrease in the expected future vesting rates of the Performance Share Plans (PSP) and the Value Creation Plan (VCP).

F-17 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

18 Other reserves

Net unrealised (losses)/ Foreign Reserve for gains on currency share-based derivatives translation payments Total US$m US$m US$m US$m Balance at 1 January 2013 ...... — (25) 63 38 Foreign currency translation ...... — (27) — (27) Net losses on maturity of cash flow hedges recycled in the period ...... 1 — — 1 Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... (3) — — (3) Share-based payments charge (note 17) ...... — — 7 7 Transfer during the year (note 17) ...... — — 22 22 Shares vested during the year ...... — — (29) (29) Balance at 30 June 2013 (unaudited) ...... (2) (52) 63 9 Balance at 1 January 2012 ...... (20) (35) 61 6 Foreign currency translation ...... — (3) — (3) Net losses on maturity of cash flow hedges recycled in the period ...... 12 — — 12 Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... (11) — — (11) Share-based payments charge (note 17) ...... — — 13 13 Transfer during the year (note 17) ...... — — 20 20 Shares vested during the year ...... — — (41) (41) Deferred tax on share based payments reserve ...... — — 1 1 Balance at 30 June 2012 (unaudited) ...... (19) (38) 54 (3) Balance at 1 January 2012 ...... (20) (35) 61 6 Foreign currency translation ...... — 10 — 10 Net losses on maturity of cash flow hedges recycled in the year . . 20 — — 20 Share-based payments charge (note 17) ...... — — 26 26 Transfer during the year (note 17) ...... — — 20 20 Shares vested during the year ...... — — (45) (45) Deferred tax on share based payments reserve ...... — — 1 1 Balance at 31 December 2012 (audited) ...... — (25) 63 38

F-18 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

19 Interest-bearing loans and borrowings The Group had the following interest-bearing loans and borrowings outstanding:

30 June 2013 30 June 2012 31 December 30 June 30 June 31 December Actual Actual 2012 Actual Effective 2013 2012 2012 interest rate interest rate interest rate interest rate Unaudited Unaudited Audited % % % % Maturity US$m US$m US$m Current Bank overdrafts (i) US/UK LIBOR US/UK LIBOR US/UK LIBOR US/UK LIBOR on demand 53 37 57 + 1.50% + 1.50% + 1.50% + 1.50% Other loans: Current portion of (iii) US LIBOR — — US LIBOR 20 —— project financing + 2.70% + 2.70% Current portion of (iv) — US/UK LIBOR — n/a n/a — 19 — term loan + 0.875% Current portion of (iv) — US/UK LIBOR — n/a n/a — 9— term loan + 0.875% 73 65 57 Non-current Revolving credit (ii) US LIBOR — US LIBOR US LIBOR 5 years 720 — 303 facility + 1.50% + 1.50% + 1.50% Project Financing (iii) US LIBOR — — US LIBOR 7 years 128 —— + 2.70% + 2.70% Term loan (iv) — US/UK LIBOR — n/a n/a — 2— + 0.875% Term loan (iv) — US/UK LIBOR — n/a n/a — 3— + 0.875% 848 5 303 Less: Debt acquisition costs net of accumulated amortisation and effective interest rate adjustments (13) (3) (11) 835 2 292

Details of the Group’s interest-bearing loans and borrowings are as follows:

(i) Bank overdrafts Bank overdrafts are drawn down in US dollars and sterling denominations to meet the Group’s working capital requirements. These are repayable on demand.

(ii) Revolving Credit Facility On 11 September 2012, Petrofac entered into a US$1,200m 5 year committed revolving credit facility with a syndicate of 13 international banks, which is available for general corporate purposes. The facility, which matures on 11 September 2017, is unsecured and is subject to two financial covenants relating to leverage and interest cover. During the period a net amount of US$417m (30 June 2012: US$nil; 31 December 2012: US$303m) was drawn under this facility. Interest is payable on the current drawn balance of the facility at LIBOR + 1.50% and in addition utilisation fees are payable depending on the level of utilisation.

(iii) Project Financing In May 2013, Berantai Floating Production Limited entered into a US$300m (Group’s 51% share US$153m) senior secured term loan facility with a syndicate of 4 banks to refinance the cost of obtaining and developing the Berantai FPSO. The loan, which was advanced in full in May 2013, will be amortised on a quarterly basis and has a final maturity date of October 2019. The facility contains a Debt Service Coverage Ratio financial covenant of not less than 1.15:1. Interest on the loan is calculated at LIBOR plus a margin of 2.70%. Underlying LIBOR has been hedged at 1.675% for the duration of the loan. In addition the borrower paid arrangement, co-ordinating, facility agent and security arrangement fees, the sum of which have been capitalised and are being amortised over the term of the loan.

F-19 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

19 Interest-bearing loans and borrowings (continued)

(iv) Term loans The loans were repaid in full during the second half of 2012.

20 Capital commitments At 30 June 2013 the Group had capital commitments of US$570m (30 June 2012: US$612m; 31 December 2012: US$493m).

Included in the US$570m of commitments are:

30 June 30 June 31 December 2013 2012 2012 Unaudited Unaudited Audited US$m US$m US$m Further appraisal and development of wells on Group’s assets in Malaysia ...... 425 282 287 Costs in respect of Ithaca Greater Stella Field development in the North Sea ...... 78 82 50 Production Enhancement Contracts in Mexico ...... 63 185 146

21 Related party transactions The following table provides the total amount of transactions which have been entered into with related parties:

Amounts Amounts Sales Purchases owed owed to from by related to related related related parties parties parties parties US$m US$m US$m US$m (Restated) (Restated) Joint ventures ...... Six months ended 30 June 2013 (unaudited) 6 — 29 1 Six months ended 30 June 2012 (unaudited) 85 87 4 58 Year ended 31 December 2012 (audited) 170 135 5 34 Associates ...... Six months ended 30 June 2013 (unaudited) — — — — Six months ended 30 June 2012 (unaudited) 1 — 6 — Year ended 31 December 2012 (audited) 3 — 5 — Key management ..... Six months ended 30 June 2013 (unaudited) — — — — personnel ...... Sixmonths ended 30 June 2012 (unaudited) — 1 — — interests ...... Year ended 31 December 2012 (audited) — 2 — —

All sales to and purchases from joint ventures are made at normal market prices and the pricing policies and terms of these transactions are approved by the Group’s management.

All related party balances at 30 June 2013 will be settled in cash.

Purchases in respect of key management personnel interests of US$259,000 (six months ended 30 June 2012: US$639,000; year ended 31 December 2012: US$1,521,000) reflect the costs of chartering the services of an aeroplane used for the transport of senior management and Directors of the Group on company business, which is owned by an offshore trust of which the Group Chief Executive of the Company is a beneficiary. The charter rates charged for Group usage of the aeroplane are significantly less than comparable market rates and the usage of the aeroplane is reviewed on a regular basis by the Group’s Audit Committee.

Also included in purchases in respect of key management personnel interests is US$45,000 (six months ended 30 June 2012: US$31,000; year ended 31 December 2012: US$189,000) relating to client entertainment provided by a business owned by a member of the Group’s key management.

F-20 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

21 Related party transactions (continued)

In addition to the amounts due from associates shown above there is a balance of US$12m included in investments in associates (note 14).

Compensation of key management personnel

Six months Six months ended ended Year ended 30 June 30 June 31 December 2013 2012 2012 Unaudited Unaudited Audited US$m US$m US$m Short-term employee benefits ...... 5 521 Share-based payments ...... (1) 58 Fees paid to non-executive Directors ...... 1 —1 5 10 30

The reduction in the share-based payments expense for the period compared with the equivalent period in the prior year is due to a significant decrease in the expected future vesting rates of the Performance Share Plans (PSP) and the Value Creation Plan (VCP).

22 Financial instruments Fair values of financial assets and liabilities Set out below is a comparison of the carrying amounts and fair values of financial instruments as at 30 June 2013:

Carrying amount Fair value Unaudited Unaudited US$m US$m Financial assets Cash and short-term deposits ...... 538 538 Seven Energy warrants ...... 12 12 Restricted cash ...... 77 Oil derivative ...... 22 Financial liabilities Interest-bearing loans and borrowings ...... 908 921 Contingent consideration ...... 88 Forward currency contracts—designated as cash flow hedge ...... 55 Forward currency contracts—undesignated ...... 22

Fair values of financial assets and liabilities Market values have been used to determine the fair values of available-for-sale financial assets, forward currency contracts and oil derivatives. The fair value of warrants over equity instruments in Seven Energy has been calculated using a Black Scholes option valuation model (note 15). The fair values of long-term interest-bearing loans and borrowings are equivalent to their amortised costs determined as the present value of discounted future cash flows using the effective interest rate. The Company considers that the carrying amounts of trade and other receivables, work-in-progress, trade and other payables, other current and non-current financial assets and liabilities approximate their fair values and are therefore excluded from the above table.

F-21 Notes to the Interim Condensed Consolidated Financial Statements For the six months ended 30 June 2013

22 Financial instruments (continued)

Fair value hierarchy The following financial instruments are measured at fair value using the hierarchy below for determination and disclosure of their respective fair values:

Tier 1: Unadjusted quoted prices in active markets for identical financial assets or liabilities Tier 2: Other valuation techniques where the inputs are based on all observation data (directly or indirectly) Tier 3: Other valuation techniques where the inputs are based on unobservable market data

As at 30 June 2013, the Group held the following classes of financial instruments measured at fair value:

Tier 2 Tier 3 Unaudited Unaudited US$m US$m Financial assets Seven Energy warrants ...... —12 Oil derivative ...... 2—

Financial liabilities Forward currency contracts – designated as cash flow hedge ...... 5— Forward currency contracts – undesignated ...... 2—

Valuation techniques Foreign currency forward contracts The foreign currency forward contracts are measured based on observable spot exchange rates, the yield curves of the respective currencies as well as the currency basis spreads between the respective currencies. All contracts are fully cash collateralised, thereby eliminating both counterparty and the Group’s own credit risk.

Statement of directors’ responsibilities The Directors confirm that, to the best of their knowledge, the condensed set of financial statements on pages 17 to 40 has been prepared in accordance with IAS 34 ‘Interim Financial Reporting’, and that the interim management report on pages 1 to 16 includes a fair review of the information required by DTR 4.2.7R and DTR 4.2.8R.

The Directors of Petrofac Limited are listed in the Petrofac Annual Report and Accounts 2012.

By the order of the Board

Tim Weller Chief Financial Officer 23 August 2013

F-22 Business review Petrofac shares are traded on the London Stock Exchange using code ‘PFC.L’.

Registrar Company Secretary and registered office

Capita Registrars (Jersey) Limited Ogier Corporate Services (Jersey) Limited 12 Castle Street Ogier House St Helier The Esplanade Jersey JE23RT St Helier Jersey JE4 9WG

UK Transfer Agent Legal Advisers to the Company

Capita Registrars Freshfields Bruckhaus Deringer LLP The Registry 65 Fleet Street 34 Beckenham Road London EC4Y 1HS Beckenham Kent BR3 4TU

Corporate Brokers Auditors

Goldman Sachs Ernst & Young LLP Peterborough Court 1 More London Place 133 Fleet Street London SE1 2AF London EC4A 2BB

JP Morgan Cazenove Corporate and Financial PR 25 Bank Street Canary Wharf Tulchan Communications Group London E14 5JP 85 Fleet Street London EC4Y 1AE

Financial calendar

20 September 2013 Interim dividend record date 18 October 2013 Interim dividend payment 31 December 2013 2013 financial year end 26 February 2014 2013 full year results announcement

Dates correct at time of print, but subject to change.

The Group’s investor relations website can be found through www.petrofac.com.

F-23 Independent auditor’s report to the members of Petrofac Limited

We have audited the Group financial statements of Petrofac Limited for the year ended 31 December 2012 which comprise the consolidated income statement, the consolidated statement of comprehensive income, the consolidated statement of financial position, the consolidated statement of cash flows, the consolidated statement of changes in equity and the related notes 1 to 32. The financial reporting framework that has been applied in their preparation is applicable law and International Financial Reporting Standards.

This report is made solely to the company’s members, as a body, in accordance with Article 113A of the Companies (Jersey) Law 1991 and our engagement letter dated 15 February 2011. Our audit work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company’s members as a body, for our audit work, for this report, or for the opinions we have formed.

Respective responsibilities of Directors and auditor As explained more fully in the Directors’ Responsibilities Statement set out on page 104, the directors are responsible for the preparation of the Group financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the Group financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors.

In addition the Company has also instructed us to: • report as to whether the information given in the Corporate Governance Statement with respect to internal control and risk Management systems in relation to financial reporting processes and about share capital structures is consistent with the financial statements • review the Directors’ statement in relation to going concern as set out on page 104, which for a premium listed UK incorporated company is specified for review by the Listing Rules of the Financial Services Authority

Scope of the audit of the financial statements An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting policies are appropriate to the Group’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant accounting estimates made by the directors; and the overall presentation of the financial statements. In addition, we read all the financial and non-financial information in the Annual report to identify material inconsistencies with the audited financial statements. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.

Opinion on financial statements In our opinion the Group financial statements: • give a true and fair view of the state of the Group’s affairs as at 31 December 2012 and of its profit for the year then ended • have been properly prepared in accordance with International Financial Reporting Standards and • have been prepared in accordance with the requirements of the Companies (Jersey) Law 1991

Opinions on other matters In our opinion, the information given in the Corporate Governance Statement set out on pages 64 to 87 with respect to internal control and risk management systems in relation to financial reporting processes and about share capital structures is consistent with the financial statements.

F-24 Matters on which we are required to report by exception We have nothing to report in respect of the following: • where the Companies (Jersey) Law 1991 requires us to report to you if, in our opinion: • proper accounting records have not been kept, or proper returns adequate for our audit have not been received from branches not visited by us; or • the financial statements are not in agreement with the accounting records and returns; or • we have not received all the information and explanations we require for our audit • under the Listing Rules we are required to review the part of the Corporate Governance Statement relating to the Company’s compliance with the nine provisions of the UK Corporate Governance Code specified for our review • where the Company instructed us to review the directors’ statement, set out on page 104, in relation to going concern

Other matter We have reported separately on the parent company financial statements of Petrofac Limited for the year ended 31 December 2012 and on the information in the Directors’ Remuneration Report that is described as having been audited.

Justine Belton for and on behalf of Ernst & Young LLP London

26 February 2013

Notes: 1 The maintenance and integrity of the Petrofac Limited web site is the responsibility of the directors; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the web site. 2 Legislation in Jersey governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

F-25 Consolidated income statement For the year ended 31 December 2012

2012 2011 Notes US$m US$m Revenue ...... 4a 6,324 5,801 Cost of sales ...... 4b (5,244) (4,841) Gross profit ...... 1,080 960 Selling, general and administration expenses ...... 4c (359) (283) Other income ...... 4f 65 12 Other expenses ...... 4g (20) (5) Profit from operations before tax and finance (costs)/income ...... 766 684 Finance costs ...... 5 (5) (7) Finance income ...... 5 12 8 Share of losses of associates ...... 12 (8) (4) Profit before tax ...... 765 681 Income tax expense ...... 6 (135) (141) Profit for the year ...... 630 540 Attributable to: Petrofac Limited shareholders ...... 632 540 Non-controlling interests ...... (2) — 630 540 Earnings per share (US cents) ...... 7 – Basic ...... 185.55 159.01 – Diluted ...... 183.88 157.13

The attached notes 1 to 32 form part of these consolidated financial statements.

F-26 Consolidated statement of comprehensive income For the year ended 31 December 2012

2012 2011 Notes US$m US$m Profit for the year ...... 630 540 Foreign currency translation gains/(losses) ...... 23 10 (16) Net loss/(gain) on maturity of cash flow hedges recycled in the period ...... 23 20 (3) Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... 23 — (14) Other comprehensive income ...... 30 (33) Total comprehensive income for the period ...... 660 507 Attributable to: Petrofac Limited shareholders ...... 662 507 Non-controlling interests ...... (2) — 660 507

The attached notes 1 to 32 form part of these consolidated financial statements.

F-27 Consolidated statement of financial position At 31 December 2012

2012 2011 Notes US$m US$m Assets Non-current assets Property, plant and equipment ...... 9 905 594 Goodwill ...... 10 125 107 Intangible assets ...... 11 307 122 Investments in associates ...... 12 177 164 Other financial assets ...... 14 444 140 Deferred income tax assets ...... 6c 43 29 2,001 1,156 Current assets Non-current asset held for sale ...... 15 — 44 Inventories ...... 16 27 11 Work in progress ...... 17 656 612 Trade and other receivables ...... 18 1,915 1,353 Due from related parties ...... 30 22 99 Other financial assets ...... 14 85 30 Income tax receivable ...... 12 15 Cash and short-term deposits ...... 19 614 1,572 3,331 3,736 Total assets ...... 5,332 4,892 Equity and liabilities Equity attributable to Petrofac Limited shareholders Share capital ...... 20 7 7 Share premium ...... 4 2 Capital redemption reserve ...... 11 11 Treasury shares ...... 21 (100) (75) Other reserves ...... 23 38 6 Retained earnings ...... 1,589 1,161 1,549 1,112 Non-controlling interests ...... 1 3 Total equity ...... 1,550 1,115 Non-current liabilities Interest-bearing loans and borrowings ...... 24 292 16 Provisions ...... 25 100 60 Other financial liabilities ...... 26 8 24 Deferred income tax liabilities ...... 6c 143 60 543 160 Current liabilities Trade and other payables ...... 27 1,981 1,742 Due to related parties ...... 30 38 23 Interest-bearing loans and borrowings ...... 24 57 61 Other financial liabilities ...... 26 17 32 Liabilities directly associated with non-current asset held for sale ...... 15 — 5 Income tax payable ...... 75 96 Billings in excess of cost and estimated earnings ...... 17 328 389 Accrued contract expenses ...... 28 743 1,269 3,239 3,617 Total liabilities ...... 3,782 3,777 Total equity and liabilities ...... 5,332 4,892

The financial statements on pages F-4 to F-57 were approved by the Board of Directors on 26 February 2013 and signed on its behalf by Tim Weller – Chief Financial Officer.

The attached notes 1 to 32 form part of these consolidated financial statements.

F-28 Consolidated statement of cash flows For the year ended 31 December 2012

2012 2011 Notes US$m US$m Operating activities Profit before tax ...... 765 681 Non-cash adjustments to reconcile profit before tax to net cash flows: Depreciation, amortisation, impairment and write off ...... 4b,4c 130 80 Share-based payments ...... 4d 26 23 Difference between other long-term employment benefits paid and amounts recognised in the income statement ...... 11 9 Net finance income ...... 5 (7) (1) Loss/(gain) on fair value changes in Seven Energy warrants ...... 4g,4f 6 (6) Gain on disposal of an investment in a joint venture ...... 4f (6) — Share of losses of associates ...... 12 8 4 Gain on disposal of non-current asset held for sale ...... 4f (27) — Fair value gain on initial recognition of investment in associate ...... 12 (9) — Debt acquisition costs written off ...... 3 — Other non-cash items, net ...... 7 6 907 796 Working capital adjustments: Trade and other receivables ...... (549) (301) Work in progress ...... (44) 192 Due from related parties ...... 77 (99) Inventories ...... (16) (3) Other current financial assets ...... (68) 17 Trade and other payables ...... 253 735 Billings in excess of cost and estimated earnings ...... (61) 211 Accrued contract expenses ...... (525) (7) Due to related parties ...... 15 12 (11) 1,553 Long-term receivable from a customer ...... 14 (300) (130) Other non-current items, net ...... (4) — Cash (used in)/generated from operations ...... (315) 1,423 Interest paid ...... (3) (3) Income taxes paid, net ...... (83) (157) Net cash flows (used in)/from operating activities ...... (401) 1,263 Investing activities Purchase of property, plant and equipment ...... (397) (420) Acquisition of subsidiaries, net of cash acquired ...... (20) — Payment of contingent consideration on acquisition ...... (1) (16) Purchase of other intangible assets ...... 11 (7) (6) Purchase of intangible oil and gas assets ...... 11 (165) (40) Investments in associates ...... 12 (25) (50) Proceeds from disposal of property, plant and equipment ...... 1 — Proceeds from disposal of non-current asset held for sale ...... 60 — Proceeds from disposal of an investment in a joint venture ...... 5 — Interest received ...... 5 9 Net cash flows used in investing activities ...... (544) (523) Financing activities Interest bearing loans and borrowings obtained, net of debt acquisition cost ...... 291 — Repayment of interest-bearing loans and borrowings ...... (50) (19) Treasury shares purchased ...... 21 (76) (49) Equity dividends paid ...... (201) (159) Net cash flows used in financing activities ...... (36) (227) Net increase/(decrease) in cash and cash equivalents ...... (981) 513 Net foreign exchange difference ...... 3 (12) Cash and cash equivalents at 1 January ...... 1,535 1,034 Cash and cash equivalents at 31 December ...... 19 557 1,535

The attached notes 1 to 32 form part of these consolidated financial statements.

F-29 Consolidated statement of changes in equity For the year ended 31 December 2012

Attributable to shareholders of Petrofac Limited Issued Capital *Treasury Other Non- share Share redemption Shares to shares reserves Retained controlling Total capital premium reserve be issued US$m US$m earnings Total interests equity US$m US$m US$m US$m (note 21) (note 23) US$m US$m US$m US$m Balance at 1 January 2012 ...... 7 2 11 — (75) 6 1,161 1,112 3 1,115 Net profit for the year ...... — — — — — — 632 632 (2) 630 Other comprehensive income ...... — — — — — 30 — 30 — 30 Total comprehensive income for the year ...... — — — — — 30 632 662 (2) 660 Shares issued as payment of consideration on acquisition ...... — 2 — — — — — 2 — 2 Share-based payments charge (note 22) ...... — — — — — 26 — 26 — 26 Shares vested during the year (note 21) ...... — — — — 51 (45) (6) — — — Transfer to reserve for share- based payments (note 22) ...... — — — — — 20 — 20 — 20 Treasury shares purchased (note 21) ...... — — — — (76) — — (76) — (76) Income tax on share-based payments reserve ...... — — — — — 1 — 1 — 1 Dividends (note 8) ...... — — — — — — (198) (198) — (198) Balance at 31 December 2012 ...... 7 4 11 — (100) 38 1,589 1,549 1 1,550

Attributable to shareholders of Petrofac Limited Issued Capital *Treasury Other Non- share Share redemption Shares to shares reserves Retained controlling Total capital premium reserve be issued US$m US$m earnings Total interests equity US$m US$m US$m US$m (note 21) (note 23) US$m US$m US$m US$m Balance at 1 January 2011 ...... 7 1 11 1 (65) 35 787 777 3 780 Net profit for the year ...... — — — — — — 540 540 — 540 Other comprehensive income ...... — — — — — (33) — (33) — (33) Total comprehensive income for the year ...... — — — — — (33) 540 507 — 507 Shares issued as payment of consideration on acquisition ...... — 1 — (1) — — — — — — Share-based payments charge (note 22) ...... — — — — — 23 — 23 — 23 Shares vested during the year (note 21) ...... — — — — 39 (34) (5) — — — Transfer to reserve for share- based payments (note 22) ...... — — — — — 18 — 18 — 18 Treasury shares purchased (note 21) ...... — — — — (49) — — (49) — (49) Income tax on share-based payments reserve ...... — — — — — (3) — (3) — (3) Dividends (note 8) ...... — — — — — — (161) (161) — (161) Balance at 31 December 2011 ...... 7 2 11 — (75) 6 1,161 1,112 3 1,115

*Shares held by Petrofac Employee Benefit Trust and Petrofac Joint Venture Companies Employee Benefit Trust.

The attached notes 1 to 32 form part of these consolidated financial statements.

F-30 Notes to the consolidated financial statements For the year ended 31 December 2012

1 Corporate information The consolidated financial statements of Petrofac Limited (the ‘Company’) for the year ended 31 December 2012 were authorised for issue in accordance with a resolution of the Directors on 26 February 2013.

Petrofac Limited is a limited liability company registered and domiciled in Jersey under the Companies (Jersey) Law 1991 and is the holding company for the international group of Petrofac subsidiaries (together the ‘Group’). The Company’s 31 December 2012 financial statements are shown on pages 152 to 165. The Group’s principal activity is the provision of services to the oil and gas production and processing industry.

The principal Group companies, and joint venture entities, are contained in note 32 to these consolidated financial statements.

Statement of compliance The consolidated financial statements of Petrofac Limited and its subsidiaries have been prepared in accordance with International Financial Reporting Standards (IFRS) and applicable requirements of Jersey law.

Basis of consolidation The consolidated financial statements comprise the financial statements of Petrofac Limited and its subsidiaries. The financial statements of its subsidiaries are prepared for the same reporting year as the Company and where necessary, adjustments are made to the financial statements of the Group’s subsidiaries to bring their accounting policies into line with those of the Group.

Subsidiaries are consolidated from the date on which control is transferred to the Group and cease to be consolidated from the date on which control is transferred out of the Group. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities. All intra-Group balances and transactions, including unrealised profits, have been eliminated on consolidation.

Non-controlling interests in subsidiaries consolidated by the Group are disclosed separately from the Group’s equity and income statement and non-controlling interests are allocated their share of total comprehensive income for the year even if this results in a deficit balance.

New standards and interpretations The Group has adopted new and revised Standards and Interpretations issued by the International Accounting Standards Board (IASB) and the International Financial Reporting Interpretations Committee (IFRIC) of the IASB that are relevant to its operations and effective for accounting periods beginning on or after 1 January 2012. The following new amendments and enhanced disclosures did not have any current impact on the financial position, performance, or disclosures of the Group: • IAS 12 Income Taxes (Amendment) – Deferred Taxes: Recovery of Underlying Assets effective 1 January 2012 • IFRS 7 Financial Instruments: Disclosures – Enhanced Derecognition Disclosure Requirements effective 1 July 2011

F-31 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

Standards issued but not yet effective Standards issued but not yet effective up to the date of issuance of the Group’s financial statements are listed below and include only those standards and interpretations that are likely to have an impact on the disclosures, financial position or performance of the Group at a future date. The Group intends to adopt these standards when they become effective.

IAS 1 Financial Statement Presentation – Presentation of Items of Other Comprehensive Income (OCI) The amendments to IAS 1 change the grouping of items presented in OCI. Items that could be reclassified (or ‘recycled’) to profit or loss at a future point in time (for example, upon derecognition or settlement) would be presented separately from items that will never be reclassified. The amendment affects presentation only and has therefore no impact on the Group’s financial position or performance. The amendment becomes effective for annual periods beginning on or after 1 July 2012.

IAS 27 Separate Financial Statements (as revised in 2011) As a consequence of the new IFRS 10 and IFRS 12, what remains of IAS 27 is limited to accounting for subsidiaries, jointly controlled entities, and associates in separate financial statements. The amendment becomes effective for annual periods beginning on or after 1 January 2013 but is not expected to have any financial impact on the separate financial statements of the Company but will require some changes in disclosure.

IAS 28 Investments in Associates and Joint Ventures (as revised in 2011) As a consequence of the new IFRS 11 and IFRS 12, IAS 28 has been renamed IAS 28 Investments in Associates and Joint Ventures, and describes the application of the equity method to investments in joint ventures in addition to associates. The amendment becomes effective for annual periods beginning on or after 1 January 2013.

IFRS 9 Financial Instruments: Classification and Measurement IFRS 9 as issued reflects the first phase of the IASB’s work on the replacement of IAS 39 and applies to classification and measurement of financial assets and financial liabilities as defined in IAS 39. The standard is effective for annual periods beginning on or after 1 January 2015. In subsequent phases, the IASB will address hedge accounting and impairment of financial assets. The adoption of the first phase of IFRS 9 will have an effect on the classification and measurement of the Group’s financial assets, but will not have an impact on classification and measurements of financial liabilities. The Group will quantify the effect in conjunction with the other phases, when the final standard including all phases is issued.

IFRS 10 Consolidated Financial Statements IFRS 10 replaces the portion of IAS 27 Consolidated and Separate Financial Statements that addresses the accounting for consolidated financial statements. It also includes the issues raised in SIC-12 Consolidation – Special Purpose Entities.

IFRS 10 establishes a single control model that applies to all entities including special purpose entities. The changes introduced by IFRS 10 will require management to exercise significant judgement to determine which entities are controlled, and therefore, are required to be consolidated by a parent, compared with the requirements that were in IAS 27. Based on the preliminary analyses performed, IFRS 10 is not expected to have any impact on the currently held investments of the Group.

This standard becomes effective for annual periods beginning on or after 1 January 2013.

IFRS 11 Joint Arrangements IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly-controlled Entities – Non-monetary Contributions by Venturers.

F-32 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

IFRS 11 removes the option to account for jointly-controlled entities (JCEs) using proportionate consolidation. Instead, JCEs that meet the definition of a joint venture must be accounted for using the equity method.

The application of this new standard will impact the financial position of the Group by eliminating proportionate consolidation of certain joint ventures. With the application of the new standard, the investment in those joint ventures will be accounted for using the equity method of accounting. This standard becomes effective for annual periods beginning on or after 1 January 2013, and is to be applied retrospectively for joint arrangements held at the date of initial application. The expected impact of IFRS 11 on the current period (which will be the comparative period in the financial statements as of 31 December 2013), given the current status of our joint arrangements, is expected to be a reduction of revenue of US$76m and a reduction in profit from operations of US$2m as income from joint ventures will be presented outside operating profit going forward. Current assets and current liabilities will be reduced by US$47m and US$89m respectively, while the impact on non-current assets will be a reduction of US$65m and the non-current liabilities will be reduced by US$2m. The reduction in net assets above will result in recognition of investments in joint ventures which will be included within non- current assets.

IFRS 12 Disclosure of Involvement with Other Entities IFRS 12 includes all of the disclosures that were previously in IAS 27 relating to consolidated financial statements, as well as all of the disclosures that were previously included in IAS 31 and IAS 28. These disclosures relate to an entity’s interests in subsidiaries, joint arrangements, associates and structured entities. A number of new disclosures are also required. This standard becomes effective for annual periods beginning on or after 1 January 2013. The application of this standard affects disclosure only and will have no impact on the Group’s financial position or performance.

IFRS 13 Fair Value Measurement IFRS 13 establishes a single source of guidance under IFRS for all fair value measurements. IFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under IFRS when fair value is required or permitted. The Group is currently assessing the impact that this standard will have on the financial position and performance of the Group. This standard becomes effective prospectively for annual periods beginning on or after 1 January 2013.

Significant accounting judgements and estimates Judgements In the process of applying the Group’s accounting policies, management has made the following judgements, apart from those involving estimations, which have the most significant effect on the amounts recognised in the consolidated financial statements: • revenue recognition on fixed-price engineering, procurement and construction contracts: the Group recognises revenue on fixed-price engineering, procurement and construction contracts using the percentage-of-completion method, based on surveys of work performed. The Group has determined this basis of revenue recognition is the best available measure of progress on such contracts • revenue recognition on Integrated Energy Services contracts: the Group assesses on a case by case basis the most appropriate treatment for its various of commercial structures which include Risk Service Contracts, Production Enhancement Contracts and Equity Upstream Investments including Production Sharing Contracts (see accounting policies note on page F-19 for further details)

F-33 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

the Group to make estimates of future costs to be incurred, based on work to be performed beyond the statement of financial position date. This estimate will impact revenues, cost of sales, work-in-progress, billings in excess of costs and estimated earnings and accrued contract expenses • onerous contract provisions: the Group provides for future losses on long-term contracts where it is considered probable that the contract costs are likely to exceed revenues in future years. Estimating these future losses involves a number of assumptions about the achievement of contract performance targets and the likely levels of future cost escalation over time US$ nil at 31 December 2012 (2011: US$ nil) • impairment of goodwill: the Group determines whether goodwill is impaired at least on an annual basis. This requires an estimation of the value in use of the cash-generating units to which the goodwill is allocated. Estimating the value in use requires the Group to make an estimate of the expected future cash flows from each cash-generating unit and also to determine a suitable discount rate in order to calculate the present value of those cash flows. The carrying amount of goodwill at 31 December 2012 was US$125m (2011: US$107m) (note 10) • deferred tax assets: the Group recognises deferred tax assets on all applicable temporary differences where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the amount of deferred tax that can be recognised based on the magnitude and likelihood of future taxable profits. The carrying amount of deferred tax assets at 31 December 2012 was US$43m (2011: US$29m) • income tax: the Company and its subsidiaries are subject to routine tax audits and also a process whereby tax computations are discussed and agreed with the appropriate authorities. Whilst the ultimate outcome of such tax audits and discussions cannot be determined with certainty, management estimates the level of provisions required for both current and deferred tax on the basis of professional advice and the nature of current discussions with the tax authority concerned • recoverable value of intangible oil and gas and other intangible assets: the Group determines at each statement of financial position date whether there is any evidence of indicators of impairment in the carrying value of its intangible oil and gas and other intangible assets. Where indicators exist, an impairment test is undertaken which requires management to estimate the recoverable value of its intangible assets for example by reference to quoted market values, similar arm’s length transactions involving these assets or value in use calculations • units of production depreciation: estimated proven plus probable reserves are used in determining the depreciation of oil and gas assets such that the depreciation charge is proportional to the depletion of the remaining reserves over their life of production. These calculations require the use of estimates including the amount of economically recoverable reserves and future oil and gas capital expenditure

Interests in joint ventures The Group has a number of contractual arrangements with other parties which represent joint ventures. These take the form of agreements to share control over other entities (jointly controlled entities) and commercial collaborations (jointly controlled operations). These arrangements require unanimous agreement for financial and operating decisions among the venturers. The Group’s interests in jointly controlled entities are accounted for by proportionate consolidation, which involves recognising the Group’s proportionate share of the joint venture’s assets, liabilities, income and expenses with similar items in the consolidated financial statements on a line-by- line basis. Where the Group collaborates with other entities in jointly controlled operations, the expenses the Group incurs and its share of the revenue earned is recognised in the consolidated income statement. Assets controlled by the Group and liabilities incurred by it are recognised in the statement of financial position. Where necessary, adjustments are made to the financial statements of the Group’s jointly controlled entities and operations to bring their accounting policies into line with those of the Group.

Investments in associates The Group’s investment in its associates, entities in which the Group has significant influence, are accounted for using the equity method.

F-34 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

Under the equity method, the investment is initially carried at cost and adjusted for post acquisition changes in the Group’s share of net assets of the associate. Goodwill on the initial investment forms a part of the carrying amount of the investment and is not individually tested for impairment.

The Group recognises its share of the net profits after tax and non-controlling interest of the associates in its consolidated income statement. Share of associate’s changes in equity is also recognised in the Group’s consolidated statement of changes in equity. Any unrealised gains and losses resulting from transactions between the Group and the associate are eliminated to the extent of the interest in associates.

The financial statements of the associate are prepared using the same accounting policies and reporting periods as that of the Group.

The carried value of the investment is tested for impairment at each reporting date. Impairment, if any, is determined by the difference between the recoverable amount of the associate and its carrying value and is reported within the share of income of an associate in the Group’s consolidated income statement.

Foreign currency translation The Company’s functional and presentational currency is US dollars. In the financial statements of individual subsidiaries, joint ventures and associates, transactions in currencies other than a company’s functional currency are recorded at the prevailing rate of exchange at the date of the transaction. At the year end, monetary assets and liabilities denominated in foreign currencies are retranslated at the rates of exchange prevailing at the statement of financial position date. Non-monetary assets and liabilities that are measured at historical cost in a foreign currency are translated using the rate of exchange as at the dates of the initial transactions. Non-monetary assets and liabilities measured at fair value in a foreign currency are translated using the rate of exchange at the date the fair value was determined. All foreign exchange gains and losses are taken to the consolidated income statement with the exception of exchange differences arising on monetary assets and liabilities that form part of the Group’s net investment in subsidiaries. These are taken directly to the statement of changes in equity until the disposal of the net investment at which time they are recognised in the consolidated income statement.

The statements of financial position of overseas subsidiaries, joint ventures and associates are translated into US dollars using the closing rate method, whereby assets and liabilities are translated at the rates of exchange prevailing at the statement of financial position date. The income statements of overseas subsidiaries and joint ventures are translated at average exchange rates for the year. Exchange differences arising on the retranslation of net assets are taken directly to other reserves within the statement of changes in equity.

On the disposal of a foreign entity, accumulated exchange differences are recognised in the consolidated income statement as a component of the gain or loss on disposal.

Property, plant and equipment Property, plant and equipment is stated at cost less accumulated depreciation and any impairment in value. Cost comprises the purchase price or construction cost and any costs directly attributable to making that asset capable of operating as intended. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Depreciation is provided on a straight-line basis, other than on oil and gas assets, at the following rates:

Oil and gas facilities 10% – 12.5% Plant and equipment 4% – 33% Buildings and leasehold improvements 5% – 33% (or lease term if shorter) Office furniture and equipment 25% – 50% Vehicles 20% – 33%

F-35 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

Tangible oil and gas assets are depreciated, on a field-by-field basis, using the unit-of-production method based on entitlement to proven and probable reserves, taking account of estimated future development expenditure relating to those reserves.

Each asset’s estimated useful life, residual value and method of depreciation are reviewed and adjusted if appropriate at each financial year end.

No depreciation is charged on land or assets under construction.

The carrying amount of an item of property, plant and equipment is derecognised on disposal or when no future economic benefits are expected from its use or disposal. The gain or loss arising from the derecognition of an item of property, plant and equipment is included in the consolidated income statement when the item is derecognised. Gains are not classified as revenue.

Non-current assets held for sale Non-current assets or disposal Groups are classified as held for sale when it is expected that the carrying amount of an asset will be recovered principally through sale rather than continuing use. Assets are not depreciated when classified as held for sale.

Borrowing costs Borrowing costs directly attributable to the construction of qualifying assets, which are assets that necessarily take a substantial period of time to prepare for their intended use, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use. All other borrowing costs are recognised as interest payable in the consolidated income statement in the period in which they are incurred.

Goodwill Goodwill acquired in a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually, or more frequently if events or changes in circumstances indicate that such carrying value may be impaired. All transaction costs associated with business combinations are charged to the consolidated income statement in the year of such combination.

For the purpose of impairment testing, goodwill acquired is allocated to the cash-generating units that are expected to benefit from the synergies of the combination. Each unit or units to which goodwill is allocated represents the lowest level within the Group at which the goodwill is monitored for internal management purposes and is not larger than an operating segment determined in accordance with IFRS 8 ‘Operating Segments’.

Where goodwill has been allocated to cash-generating units and part of the operation within those units is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the cash- generating units retained.

Contingent consideration payable on a business combination When, as part of a business combination, the Group defers a proportion of the total purchase consideration payable for an acquisition, the amount provided for is the acquisition date fair value of the consideration. The

F-36 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued unwinding of the discount element is recognised as a finance cost in the consolidated income statement. For business combinations prior to 1 January 2010, all changes in estimated contingent consideration payable on acquisition are adjusted against the carried goodwill. For business combinations after 1 January 2010, changes in estimated contingent consideration payable on acquisition are recognised in the consolidated income statement unless they are measurement period adjustments which arise as a result of additional information obtained after the acquisition date about the facts and circumstances existing at the acquisition date, which are adjusted against carried goodwill.

Intangible assets – non oil and gas assets Intangible assets acquired in a business combination are initially measured at cost being their fair values at the date of acquisition and are recognised separately from goodwill where the asset is separable or arises from a contractual or other legal right and its fair value can be measured reliably. After initial recognition, intangible assets are carried at cost less accumulated amortisation and any accumulated impairment losses. Intangible assets with a finite life are amortised over their useful economic life using a straight-line method unless a better method reflecting the pattern in which the asset’s future economic benefits are expected to be consumed can be determined. The amortisation charge in respect of intangible assets is included in the selling, general and administration expenses line of the consolidated income statement. The expected useful lives of assets are reviewed on an annual basis. Any change in the useful life or pattern of consumption of the intangible asset is treated as a change in accounting estimate and is accounted for prospectively by changing the amortisation period or method. Intangible assets are tested for impairment whenever there is an indication that the asset may be impaired.

Oil and gas assets Capitalised costs The Group’s activities in relation to oil and gas assets are limited to assets in the evaluation, development and production phases.

Oil and gas evaluation and development expenditure is accounted for using the successful efforts method of accounting.

Evaluation expenditures Expenditure directly associated with evaluation (or appraisal) activities is capitalised as an intangible asset. Such costs include the costs of acquiring an interest, appraisal well drilling costs, payments to contractors and an appropriate share of directly attributable overheads incurred during the evaluation phase. For such appraisal activity, which may require drilling of further wells, costs continue to be carried as an asset whilst related hydrocarbons are considered capable of commercial development. Such costs are subject to technical, commercial and management review to confirm the continued intent to develop, or otherwise extract value. When this is no longer the case, the costs are written-off in the income statement. When such assets are declared part of a commercial development, related costs are transferred to tangible oil and gas assets. All intangible oil and gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the consolidated income statement.

Development expenditures Expenditure relating to development of assets which include the construction, installation and completion of infrastructure facilities such as platforms, pipelines and development wells, is capitalised within property, plant and equipment.

Changes in unit-of-production factors Changes in factors which affect unit-of-production calculations are dealt with prospectively in accordance with the treatment of changes in accounting estimates, not by immediate adjustment of prior years’ amounts.

F-37 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

Decommissioning Provision for future decommissioning costs is made in full when the Group has an obligation to dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. The amount recognised is the present value of the estimated future expenditure. An amount equivalent to the discounted initial provision for decommissioning costs is capitalised and amortised over the life of the underlying asset on a unit-of-production basis over proven and probable reserves. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the oil and gas asset.

The unwinding of the discount applied to future decommissioning provisions is included under finance costs in the consolidated income statement.

Impairment of assets (excluding goodwill) At each statement of financial position date, the Group reviews the carrying amounts of its tangible and intangible assets to assess whether there is an indication that those assets may be impaired. If any such indication exists, the Group makes an estimate of the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows attributable to the asset are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.

Where an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset in prior years. A reversal of an impairment loss is recognised immediately in the consolidated income statement, unless the relevant asset is carried at a revalued amount, in which case the reversal of the impairment is treated as a revaluation increase.

Inventories Inventories are valued at the lower of cost and net realisable value. Net realisable value is the estimated selling price in the ordinary course of business, less estimated costs of completion and the estimated costs necessary to make the sale. Cost comprises purchase price, cost of production, transportation and other directly allocable expenses. Costs of inventories, other than raw materials, are determined using the first-in-first-out method. Costs of raw materials are determined using the weighted average method.

Work in progress and billings in excess of cost and estimated earnings Fixed price lump sum engineering, procurement and construction contracts are presented in the statement of financial position as follows: • for each contract, the accumulated cost incurred, as well as the estimated earnings recognised at the contract’s percentage of completion less provision for any anticipated losses, after deducting the progress payments received or receivable from the customers, are shown in current assets in the statement of financial position under ‘work in progress’ • where the payments received or receivable for any contract exceed the cost and estimated earnings less provision for any anticipated losses, the excess is shown as ‘billings in excess of cost and estimated earnings’ within current liabilities

F-38 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

Trade and other receivables Trade receivables are recognised and carried at original invoice amount less an allowance for any amounts estimated to be uncollectable. An estimate for doubtful debts is made when there is objective evidence that the collection of the full amount is no longer probable under the terms of the original invoice. Impaired debts are derecognised when they are assessed as uncollectable.

Cash and cash equivalents Cash and cash equivalents consist of cash at bank and in hand and short-term deposits with an original maturity of three months or less. For the purpose of the cash flow statement, cash and cash equivalents consists of cash and cash equivalents as defined above, net of outstanding bank overdrafts.

Interest-bearing loans and borrowings All interest-bearing loans and borrowings are initially recognised at the fair value of the consideration received net of issue costs directly attributable to the borrowing.

After initial recognition, interest-bearing loans and borrowings are subsequently measured at amortised cost using the effective interest rate method. Amortised cost is calculated by taking into account any issue costs, and any discount or premium on settlement.

Provisions Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised in the consolidated income statement as a finance cost.

Derecognition of financial assets and liabilities Financial assets A financial asset (or, where applicable a part of a financial asset) is derecognised where: • the rights to receive cash flows from the asset have expired • the Group retains the right to receive cash flows from the asset, but has assumed an obligation to pay them in full without material delay to a third-party under a ‘pass-through’ arrangement; or • the Group has transferred its rights to receive cash flows from the asset and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset

Financial liabilities A financial liability is derecognised when the obligation under the liability is discharged or cancelled or expires.

If an existing financial liability is replaced by another from the same lender, on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability such that the difference in the respective carrying amounts together with any costs or fees incurred are recognised in the consolidated income statement.

F-39 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued respect of pension costs reflects the contributions payable in the year. Differences between contributions payable during the year and contributions actually paid are shown as either accrued liabilities or prepaid assets in the statement of financial position.

The Group’s other long-term employment benefits are provided in accordance with the labour laws of the countries in which the Group operates, further details of which are given in note 25.

Share-based payment transactions Employees (including Directors) of the Group receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares (‘equity-settled transactions’).

Equity-settled transactions The cost of equity-settled transactions with employees is measured by reference to the fair value at the date on which they are granted. In valuing equity-settled transactions, no account is taken of any service or performance conditions, other than conditions linked to the price of the shares of Petrofac Limited (‘market conditions’), if applicable.

The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the relevant employees become fully entitled to the award (the ‘vesting period’). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group’s best estimate of the number of equity instruments that will ultimately vest. The income statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

No expense is recognised for awards that do not ultimately vest, except for awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions and service conditions are satisfied. Equity awards cancelled are treated as vesting immediately on the date of cancellation, and any expense not recognised for the award at that date is recognised in the consolidated income statement.

Petrofac Employee Benefit Trusts The Petrofac Employee Benefit Trust and the Petrofac Joint Venture Companies Employee Benefit Trust warehouse ordinary shares purchased to satisfy various new share scheme awards made to the employees of the Company and its joint venture partner employees, which will be transferred to the members of the scheme on their respective vesting dates subject to satisfying the performance conditions of each scheme. The trusts have been consolidated in the Group financial statements in accordance with SIC 12 ‘Special Purpose Entities’. The cost of shares temporarily held by the trusts are reflected as treasury shares and deducted from equity.

Leases The determination of whether an arrangement is, or contains a lease is based on the substance of the arrangement at inception date and whether the fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys the right to use the asset.

Leases are classified as finance leases whenever the terms of the lease transfer substantially all the risks and rewards of ownership to the lessee. All other leases are classified as operating leases.

Assets held under finance leases are recognised as non-current assets of the Group at the lower of their fair value at the date of commencement of the lease and the present value of the minimum lease payments. These assets are depreciated on a straight-line basis over the shorter of the useful life of the asset and the lease term. The corresponding liability to the lessor is included in the consolidated statement of financial position as a finance lease obligation. Lease payments are apportioned between finance costs in the income statement and reduction of the lease obligation so as to achieve a constant rate of interest on the remaining balance of the liability.

F-40 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

The Group has entered into various operating leases the payments for which are recognised as an expense in the consolidated income statement on a straight-line basis over the lease terms.

Revenue recognition Revenue is recognised to the extent that it is probable economic benefits will flow to the Group and the revenue can be reliably measured. The following specific recognition criteria also apply:

Onshore Engineering & Construction Revenues from fixed-price lump-sum contracts are recognised on the percentage-of-completion method, based on surveys of work performed once the outcome of a contract can be estimated reliably. In the early stages of contract completion, when the outcome of a contract cannot be estimated reliably, contract revenues are recognised only to the extent of costs incurred that are expected to be recoverable.

Revenues from cost-plus-fee contracts are recognised on the basis of costs incurred during the year plus the fee earned measured by the cost-to-cost method.

Revenues from reimbursable contracts are recognised in the period in which the services are provided based on the agreed contract schedule of rates.

Provision is made for all losses expected to arise on completion of contracts entered into at the statement of financial position date, whether or not work has commenced on these contracts.

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded and the amount of the incentive payments can be measured reliably. Variation orders are only included in revenue when it is probable they will be accepted and can be measured reliably and claims are only included in revenue when negotiations have reached an advanced stage.

Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services Revenues from reimbursable contracts are recognised in the period in which the services are provided based on the agreed contract schedule of rates.

Revenues from fixed-price contracts are recognised on the percentage-of-completion method, measured by milestones completed or earned value once the outcome of a contract can be estimated reliably. In the early stages of contract completion, when the outcome of a contract cannot be estimated reliably, contract revenues are recognised only to the extent of costs incurred that are expected to be recoverable.

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded 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.

Integrated Energy Services Oil and gas revenues comprise the Group’s share of sales from the processing or sale of hydrocarbons on an entitlement basis, when the significant risks and rewards of ownership have been passed to the buyer.

Revenue from production enhancement contracts is recognised based on the volume of hydrocarbons produced in the period and the agreed tariff and the reimbursement arrangement for costs incurred.

Pre-contract/bid costs Pre-contract/bid costs incurred are recognised as an expense until there is a high probability that the contract will be awarded, after which all further costs are recognised as assets and expensed over the life of the contract.

F-41 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

Income taxes Income tax expense represents the sum of current income tax and deferred tax.

Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid to the taxation authorities. Taxable profit differs from profit as reported in the consolidated income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group’s liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the statement of financial position date.

Deferred income tax is recognised on all temporary differences at the statement of financial position date between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, with the following exceptions: • where the temporary difference arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss • in respect of taxable temporary differences associated with investments in subsidiaries, associates and joint ventures, where the timing of reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future; and • deferred income tax assets are recognised only to the extent that it is probable that a taxable profit will be available against which the deductible temporary differences, carried forward tax credits or tax losses can be utilised

Derivative financial instruments and hedging The Group uses derivative financial instruments such as forward currency contracts and oil price collars and forward contracts to hedge its risks associated with foreign currency and oil price fluctuations. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.

Any gains or losses arising from changes in the fair value of derivatives that do not qualify for hedge accounting are taken to the consolidated income statement.

The fair value of forward currency contracts is calculated by reference to current forward exchange rates for contracts with similar maturity profiles. The fair value of oil price collar contracts is determined by reference to market values for similar instruments.

For the purposes of hedge accounting, hedges are classified as: • fair value hedges when hedging the exposure to changes in the fair value of a recognised asset or liability; or • cash flow hedges when hedging exposure to variability in cash flows that is either attributable to a particular risk associated with a recognised asset or liability or a highly probable forecast transaction

F-42 Notes to the consolidated financial statements continued For the year ended 31 December 2012

2 Summary of significant accounting policies continued

The Group formally designates and documents the relationship between the hedging instrument and the hedged item at the inception of the transaction, as well as its risk management objectives and strategy for undertaking various hedge transactions. The documentation also includes identification of the hedging instrument, the hedged item or transaction, the nature of risk being hedged and how the Group will assess the hedging instrument’s effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk. The Group also documents its assessment, both at hedge inception and on an ongoing basis, of whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values or cash flows of the hedged items.

The treatment of gains and losses arising from revaluing derivatives designated as hedging instruments depends on the nature of the hedging relationship, as follows:

Cash flow hedges For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognised directly in the statement of changes in equity, while the ineffective portion is recognised in the consolidated income statement. Amounts taken to equity are transferred to the consolidated income statement when the hedged transaction affects the consolidated income statement.

If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked, any cumulative gain or loss existing in equity at that time remains in equity and is recognised when the forecast transaction is ultimately recognised in the consolidated income statement. When a forecast transaction is no longer expected to occur, the cumulative gain or loss that was reported in the statement of changes in equity is immediately transferred to the consolidated income statement.

Embedded derivatives Contracts are assessed for the existence of embedded derivatives at the date that the Group first becomes party to the contract, with reassessment only if there is a change to the contract that significantly modifies the cash flows. Embedded derivatives which are not clearly and closely related to the underlying asset, liability or transaction are separated and accounted for as standalone derivatives.

3 Segment information The Group delivers its services through the four reporting segments set out below: • Onshore Engineering & Construction which provides engineering, procurement and construction project execution services to the onshore oil and gas industry • Offshore Projects & Operations which provides offshore engineering, operations and maintenance on and offshore and engineering, procurement and construction project execution services to the offshore oil and gas industry • Engineering & Consulting Services which provides technical engineering, consultancy, conceptual design, front end engineering and design (FEED) and project management consultancy (PMC) across all sectors including renewables and carbon capture • Integrated Energy Services which co-invests with partners in oil and gas production, processing and transportation assets, provides production improvement services under value aligned commercial structures and oil and gas related technical competency training and consultancy services

Management separately monitors the trading results of its four reporting segments for the purpose of making an assessment of their performance and making decisions about how resources are allocated to them. Each segment’s performance is measured based on its profitability which is reflected in a manner consistent with the results shown below. However, certain shareholder services related overheads, Group financing and consolidation adjustments are managed at a corporate level and are not allocated to reporting segments.

F-43 Notes to the consolidated financial statements continued For the year ended 31 December 2012

3 Segment information continued

The following tables represent revenue and profit information relating to the Group’s reporting segments for the year ended 31 December 2012.

Year ended 31 December 2012

Onshore Engineering Consolidation Engineering Offshore & Integrated adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & others eliminations Total US$m US$m US$m US$m US$m US$m US$m Revenue External sales ...... 4,332 1,237 100 704 — *(49) 6,324 Inter-segment sales ...... 26 166 148 15 — (355) — Total revenue ...... 4,358 1,403 248 719 — (404) 6,324 Segment results ...... 540 79 30 141 6 (26) 770 Unallocated corporate costs ...... — — — — (4) — (4) Profit/(loss) before tax and finance income/(costs) ...... 540 79 30 141 2 (26) 766 Share of losses of associates ...... — — — (8) — — (8) Finance costs ...... — — — (4) (6) 5 (5) Finance income ...... 8 — 1 7 9 (13) 12 Profit/(loss) before income tax ...... 548 79 31 136 5 (34) 765 Income tax (expense)/income ...... (69) (18) (4) (47) 8 (5) (135) Non-controlling interests ...... — — 2 — — — 2 Profit/(loss) for the year attributable to Petrofac Limited shareholders ...... 479 61 29 89 13 (39) 632 Other segment information Capital expenditures: Property, plant and equipment ...... 76 13 7 355 4 (25) 430 Intangible oil and gas assets ...... — — — 165 — — 165 Charges: Depreciation ...... 40 15 5 55 6 (2) 119 Amortisation and net impairment .... — 1 1 8 1 — 11 Other long-term employment benefits ...... 16 1 — 1 — 1 19 Share-based payments ...... 13 3 1 5 4 — 26

* Elimination of external sales shown above of US$49m represents a Group adjustment to the overall project percentage of completion on the Laggan Tormore project as OEC and OPO are reflecting in their segments progress on their own respective shares of the total project scope.

F-44 Notes to the consolidated financial statements continued For the year ended 31 December 2012

3 Segment information continued

Year ended 31 December 2011

Onshore Engineering Consolidation Engineering Offshore & Integrated adjustments & Projects & Consulting Energy Corporate & Construction Operations Services Services & others eliminations Total US$m US$m US$m US$m US$m US$m US$m Revenue External sales ...... 4,068 1,165 64 504 — — 5,801 Inter-segment sales ...... 78 87 144 15 — (324) — Total revenue ...... 4,146 1,252 208 519 — (324) 5,801 Segment results ...... 554 57 33 57 — (8) 693 Unallocated corporate costs ...... — — — — (9) — (9) Profit/(loss) before tax and finance income/(costs) ...... 554 57 33 57 (9) (8) 684 Share of losses of associates ...... — — — (4) — — (4) Finance costs ...... (2) (1) — (3) (3) 2 (7) Finance income ...... 9 — — — 2 (3) 8 Profit/(loss) before income tax .... 561 56 33 50 (10) (9) 681 Income tax (expense)/income ..... (98) (12) (2) (28) 1 (2) (141) Non-controlling interests ...... — — — — — — — Profit/(loss) for the year attributable to Petrofac Limited shareholders ...... 463 44 31 22 (9) (11) 540 Other segment information Capital expenditures: Property, plant and equipment ..... 54 58 8 312 6 (3) 435 Intangible oil and gas assets ...... — — — 40 — — 40 Charges: Depreciation ...... 31 4 6 35 1 — 77 Amortisation ...... — 1 1 1 — — 3 Other long-term employment benefits ...... 12 — — 1 — — 13 Share-based payments ...... 12 2 1 4 4 — 23

F-45 Notes to the consolidated financial statements continued For the year ended 31 December 2012

3 Segment information continued

Geographical segments The following tables present revenue from external customers based on their location and non-current assets by geographical segments for the years ended 31 December 2012 and 2011.

Year ended 31 December 2012

United United Arab Other Turkmenistan Kingdom Algeria Emirates Malaysia Kuwait Qatar countries Consolidated US$m US$m US$m US$m US$m US$m US$m US$m US$m Revenues from external customers ...... 1,697 1,186 862 793 448 319 259 760 6,324

United United Arab Other Kingdom Emirates Mexico Romania Malaysia Singapore countries Consolidated US$m US$m US$m US$m US$m US$m US$m US$m Non-current assets: Property, plant and equipment ..... 68 127 86 75 382 76 91 905 Intangible oil and gas assets ...... 10 — — — 251 — 7 268 Other intangible assets ...... 13 — 16 5 — — 5 39 Goodwill ...... 107 17 — — — — 1 125

Year ended 31 December 2011

United Arab United Other Emirates Kingdom Turkmenistan Malaysia Algeria Kuwait Qatar countries Consolidated US$m US$m US$m US$m US$m US$m US$m US$m US$m Revenues from external customers ...... 1,291 939 768 653 749 379 257 765 5,801

United United Arab Other Kingdom Emirates Tunisia Algeria Malaysia Thailand countries Consolidated US$m US$m US$m US$m US$m US$m US$m US$m Non-current assets: Property, plant and equipment .... 71 105 42 27 256 48 45 594 Intangible oil and gas assets ...... 1 — — — 102 — — 103 Other intangible assets ...... 13 — — — — — 6 19 Goodwill ...... 91 15 — — — — 1 107

Revenues disclosed in the above tables are based on where the project is located. Revenues representing greater than 10% of Group revenues arose from one customer amounting to US$1,697m (2011: two customers US$1,653m) in the Onshore Engineering & Construction segment.

F-46 Notes to the consolidated financial statements continued For the year ended 31 December 2012

4 Revenues and expenses a. Revenue

2012 2011 US$m US$m Rendering of services ...... 6,205 5,651 Sale of crude oil and gas ...... 111 143 Sale of processed hydrocarbons ...... 8 7 6,324 5,801

Included in revenues from rendering of services are Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services revenues of a ‘pass-through’ nature with zero or low margins amounting to US$220m (2011: US$229m). The revenues are included as external revenues of the Group since the risks and rewards associated with recognition are assumed by the Group. b. Cost of sales Included in cost of sales for the year ended 31 December 2012 is depreciation charged on property, plant and equipment of US$101m during 2012 (2011: US$62m) (note 9).

Also included in cost of sales are forward points and ineffective portions on derivatives designated as cash flow hedges and losses on undesignated derivatives of US$2m (2011: US$6m loss). These amounts are an economic hedge of foreign exchange risk but do not meet the criteria within IAS 39 and are most appropriately recorded in cost of sales. c. Selling, general and administration expenses

2012 2011 US$m US$m Staff costs ...... 228 187 Depreciation (note 9) ...... 18 15 Amortisation (note 11) ...... 4 3 Net impairment of an investment in associate (note 12) ...... 7 — Other operating expenses ...... 102 78 359 283

Other operating expenses consist mainly of office, travel, legal and professional and contracting staff costs. d. Staff costs

2012 2011 US$m US$m Total staff costs: Wages and salaries ...... 1,179 1,045 Social security costs ...... 52 38 Defined contribution pension costs ...... 20 21 Other long-term employee benefit costs (note 25) ...... 19 13 Expense of share-based payments (note 22) ...... 26 23 1,296 1,140

Of the US$1,296m (2011: US$1,140m) of staff costs shown above, US$1,068m (2011: US$953m) is included in cost of sales, with the remainder in selling, general and administration expenses.

F-47 Notes to the consolidated financial statements continued For the year ended 31 December 2012

4 Revenues and expenses continued

The average number of payrolled staff employed by the Group during the year was 15,259 (2011: 13,212). e. Auditors’ remuneration The Group paid the following amounts to its auditors in respect of the audit of the financial statements and for other services provided to the Group:

2012 2011 US$m US$m Group audit fee ...... 1 1 Audit of accounts of subsidiaries ...... 1 1 Others ...... 1 1 3 3

Others include audit related assurance services of US$327,000 (2011: US$283,000), tax advisory services of US$235,000 (2011: US$432,000), tax compliance services of US$113,000 (2011: US$208,000) and other non- audit services of US$118,000 (2011: US$90,000). f. Other income

2012 2011 US$m US$m Foreign exchange gains ...... 9 3 Gain on disposal of non-current asset held for sale (note 15) ...... 27 — Fair value on initial recognition of investment in associate (note 12) ...... 9 — Gain on disposal of an investment in a joint venture ...... 6 — Recovery of legal claim ...... 6 — Gain on fair value changes in Seven Energy warrants (note 12) ...... — 6 Other income ...... 8 3 65 12

Gain on sale of non-current asset held for sale of US$36m comprises US$27m on disposal of 75.2% of Petrofac’s interest in Petrofac FPF1 Limited to Ithaca Energy Inc and US$9m being the increase in fair value of the remaining 24.8% interest held which is classified as an associate. g. Other expenses

2012 2011 US$m US$m Foreign exchange losses ...... 11 4 Loss on fair value changes in Seven Energy warrants (note 12) ...... 6 — Other expenses ...... 3 1 20 5

F-48 Notes to the consolidated financial statements continued For the year ended 31 December 2012

5 Finance (costs)/income

2012 2011 US$m US$m Interest payable: Long-term borrowings ...... (2) (3) Other interest, including short-term loans and overdrafts ...... (1) (2) Unwinding of discount on provisions (note 25) ...... (2) (2) Total finance cost ...... (5) (7) Interest receivable: Bank interest receivable ...... 5 8 Unwinding of discount on long-term receivables from customers ...... 7 — Total finance income ...... 12 8

6 Income tax a. Tax on ordinary activities The major components of income tax expense are as follows:

2012 2011 US$m US$m Current income tax Current income tax charge ...... 97 138 Adjustments in respect of current income tax of previous years ...... (29) 1 Deferred income tax Relating to origination and reversal of temporary differences ...... 73 9 Recognition of tax losses relating to prior periods ...... (6) — Adjustments in respect of deferred income tax of previous years ...... — (7) Income tax expense reported in the income statement ...... 135 141 Income tax reported in equity Deferred income tax related to items credited directly to equity ...... 4 5 Current income tax related to share schemes ...... (5) (4) Income tax (income)/expense reported in equity ...... (1) 1 b. Reconciliation of total tax charge A reconciliation between the income tax expense and the product of accounting profit multiplied by the Company’s domestic tax rate is as follows:

2012 2011 US$m US$m Accounting profit before tax ...... 765 681 At Jersey’s domestic income tax rate of 0% (2011: 0%) ...... — — Expected tax charge in higher rate jurisdictions ...... 160 141 Expenditure not allowable for income tax purposes ...... 13 3 Adjustments in respect of previous years ...... (36) (6) Adjustments in respect of losses not previously recognised/derecognised ...... (2) (1) Unrecognised tax losses ...... — 2 Other permanent differences ...... (1) 1 Effect of change in tax rates ...... 1 1 At the effective income tax rate of 17.7% (2011: 20.7%) ...... 135 141

The Group’s effective tax rate for the year ended 31 December 2012 is 17.7% (2011: 20.7%). A number of factors have impacted the effective tax rate this year including the net release of tax provisions held in respect of income taxes, the recognition of tax losses previously unrecognised and the mix of profits in the jurisdictions in

F-49 Notes to the consolidated financial statements continued For the year ended 31 December 2012

6 Income tax continued which profits are earned. Adjustments in respect of prior periods represent the creation or release of tax provisions following the normal review, audit and final settlement process that occurs in the territories in which the Group operates. From 1 April 2013, the main UK corporation tax rate will be 23%, subsequently reducing to 21% in 2014. The change in the main UK rate to 23% was substantively enacted as at the balance sheet date. This change will impact the reversal of the temporary difference from this date onwards, reducing the Group’s UK deferred tax assets and liabilities for the year ended 31 December 2012. It is not expected that the proposed future rate reduction will have a significant effect on the net UK deferred tax position. c. Deferred income tax Deferred income tax relates to the following:

Consolidated statement Consolidated income of financial position statement 2012 2011 2012 2011 US$m US$m US$m US$m Deferred income tax liabilities Fair value adjustment on acquisitions ...... 3 3 — 2 Accelerated depreciation ...... 121 43 78 6 Profit recognition ...... 100 14 86 6 Other temporary differences ...... — — — (2) Gross deferred income tax liabilities ...... 224 60 Deferred income tax assets Losses available for offset ...... 96 2 (94) — Decelerated depreciation for tax purposes ...... 3 2 (1) — Share scheme ...... 9 10 (1) (1) Profit recognition ...... 11 11 — (7) Other temporary differences ...... 5 4 (1) (2) Gross deferred income tax assets ...... 124 29 Net deferred tax liability/deferred income tax charge ...... 100 31 67 2 Of which Deferred income tax assets ...... 43 29 Deferred income tax liabilities ...... 143 60 d. Unrecognised tax losses and tax credits Deferred income tax assets are recognised for tax loss carry-forwards and tax credits to the extent that the realisation of the related tax benefit through the future taxable profits is probable. The Group did not recognise deferred income tax assets of US$27m (2011: US$31m). The 2011 values of unrecognised losses have been restated to reflect the revised loss position.

2012 2011 US$m US$m Expiration dates for tax losses No earlier than 2017 ...... 7 — No earlier than 2022 ...... — 9 No expiration date ...... 8 8 15 17 Tax credits (no expiration date) ...... 12 14 27 31

During 2012, the Group recognised a tax benefit from the utilisation of tax losses of US$3m (2011: US$1m), recognition of losses not previously recognised of US$6m (2011: US$ nil) and derecognition of tax losses from a prior period US$7m (2011: US$ nil).

F-50 Notes to the consolidated financial statements continued For the year ended 31 December 2012

7 Earnings per share Basic earnings per share amounts are calculated by dividing the net profit for the year attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year.

Diluted earnings per share amounts are calculated by dividing the net profit attributable to ordinary shareholders, after adjusting for any dilutive effect, by the weighted average number of ordinary shares outstanding during the year, adjusted for the effects of ordinary shares granted under the employee share award schemes which are held in trust.

The following reflects the income and share data used in calculating basic and diluted earnings per share:

2012 2011 US$m US$m Net profit attributable to ordinary shareholders for basic and diluted earnings per share .... 632 540

2012 2011 Number Number ’m ’m Weighted average number of ordinary shares for basic earnings per share ...... 340 339 Effect of dilutive potential ordinary shares granted under share-based payment schemes . . . 3 4 Adjusted weighted average number of ordinary shares for diluted earnings per share ...... 343 343

8 Dividends paid and proposed

2012 2011 US$m US$m Declared and paid during the year Equity dividends on ordinary shares: Final dividend for 2010: 30.00 cents per share ...... — 102 Interim dividend 2011: 17.40 cents per share ...... — 59 Final dividend for 2011: 37.20 cents per share ...... 127 — Interim dividend 2012: 21.00 cents per share ...... 71 — 198 161

2012 2011 US$m US$m Proposed for approval at AGM (not recognised as a liability as at 31 December) Equity dividends on ordinary shares Final dividend for 2012: 43.00 cents per share (2011: 37.20 cents per share) ...... 149 129

F-51 Notes to the consolidated financial statements continued For the year ended 31 December 2012

9 Property, plant and equipment

Land, buildings Office and furniture Assets Oil and gas Oil and gas leasehold Plant and and under assets facilities improvements equipment Vehicles equipment construction Total US$m US$m US$m US$m US$m US$m US$m US$m Cost At 1 January 2011 ...... 118 166 158 23 15 87 13 580 Additions ...... 3 306 64 5 3 30 24 435 Disposals ...... — — (2) (2) (1) (10) — (15) Transfers ...... — (44) — — — 13 (13) (44) Exchange difference ...... (3) (2) (2) — — (1) — (8) At 1 January 2012 ...... 118 426 218 26 17 119 24 948 Additions ...... 170 139 30 3 6 29 53 430 Disposals ...... — (7) (4) (10) — (2) — (23) Transfers ...... — — — — — — — — Exchange difference ...... — — 1 — — 1 — 2 At 31 December 2012 ...... 288 558 245 19 23 147 77 1,357 Depreciation At 1 January 2011 ...... (50) (118) (45) (18) (8) (54) — (293) Charge for the year ...... (14) (19) (20) (1) (4) (19) — (77) Disposals ...... — — 2 2 — 10 — 14 Transfers ...... — — — — — — — — Exchange difference ...... 2 — — — — — — 2 At 1 January 2012 ...... (62) (137) (63) (17) (12) (63) — (354) Charge for the year ...... (36) (11) (33) (2) (4) (33) — (119) Disposals ...... — 7 4 10 — 1 — 22 Transfers ...... — — — — — — — — Exchange difference ...... — — — — — (1) — (1) At 31 December 2012 ...... (98) (141) (92) (9) (16) (96) — (452) Net carrying amount: At 31 December 2012 ...... 190 417 153 10 7 51 77 905 At 31 December 2011 ...... 56 289 155 8 6 56 24 594

Additions to oil and gas assets mainly comprise field development costs relating to the Santuario and Magallanes fields of US$106m and Ticleni field of US$48m.

Additions to oil and gas facilities in 2012 mainly comprise the upgrade of the FPF5 at a cost of US$104m (2011: US$305m purchase and upgrade of the FPF1, FPSO Berantai, FPF3, FPF4 and FPF5). Transfers from oil and gas facilities in 2011 include transfer of the FPF1 to non-current asset held for sale as part of the pending Ithaca transaction (note 15).

Of the total charge for depreciation in the income statement, US$101m (2011: US$62m) is included in cost of sales and US$18m (2011: US$15m) in selling, general and administration expenses.

Assets under construction comprise expenditures incurred in relation to a new office building in the United Arab Emirates and the Group Enterprise Resource Planning (ERP) project.

F-52 Notes to the consolidated financial statements continued For the year ended 31 December 2012

9 Property, plant and equipment continued

Included in land, buildings and leasehold improvements is property, plant and equipment under finance lease agreements, for which book values are as follows:

2012 2011 Net book value US$m US$m Gross book value ...... 35 36 Addition ...... 5 — Depreciation ...... (7) (1) Exchange difference ...... 1 — At 31 December ...... 34 35

10 Goodwill A summary of the movements in goodwill is presented below:

2012 2011 US$m US$m At 1 January ...... 107 106 Acquisitions during the year ...... 15 — Re-assessment of contingent consideration payable ...... (1) 1 Exchange difference ...... 4 — At 31 December ...... 125 107

Acquisitions during the year comprise the goodwill recognised on acquisition of KW Limited of US$14m being the difference between the fair value of the consideration of US$16m and the fair value of the assets acquired of US$2m and H&L/SPD Americas S de R.L of US$1m.

Re-assessment of contingent consideration payable comprises of the increase in contingent consideration payable on SPD Group Limited of US$ nil (2011: US$1m) and a decrease in contingent consideration payable on Caltec Limited of US$1m (2011: US$ nil).

Goodwill acquired through business combinations has been allocated to three groups of cash-generating units, for impairment testing as follows: • Offshore Projects & Operations • Engineering & Consulting Services • Integrated Energy Services

These represent the lowest level within the Group at which the goodwill is monitored for internal management purposes.

Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services cash- generating units The recoverable amounts for the Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services cash-generating units have been determined based on value in use calculations, using discounted pre-tax cash flow projections. Management have adopted projection periods appropriate to each unit’s value in use. For Offshore Projects & Operations and Engineering & Consulting Services cash-generating units the cash flow projections are based on financial budgets approved by senior management covering a five-year period, extrapolated at a growth rate of 2.5%. For the Integrated Energy Services business the cash flows are based on field models over the length of the contracted period for Production Enhancement Contracts and Risk Service Contracts. For other operations included in Integrated Energy Services, cash flows are based on financial budgets approved by senior management covering a five-year period, extrapolated at a growth rate of 2.5%. The

F-53 Notes to the consolidated financial statements continued For the year ended 31 December 2012

10 Goodwill continued carrying amount of goodwill for the Offshore Projects & Operations and Engineering & Consulting Services cash-generating units are not individually significant in comparison with the total carrying amount of goodwill and therefore no analysis of sensitivities has been provided below.

Carrying amount of goodwill allocated to each group of cash-generating units

2012 2011 US$m US$m Offshore Projects & Operations unit ...... 29 28 Engineering & Consulting Services unit ...... 23 8 Integrated Energy Services unit ...... 73 71 125 107

Key assumptions used in value in use calculations for the Integrated Energy Services unit:

Market share: for the Training business which is within Integrated Energy Services, the key assumptions relate to management’s assessment of maintaining the unit’s market share in the UK and developing further the business in international markets.

Capital expenditure: the Production Enhancement Contracts in the Integrated Energy Services unit require a minimum level of capital spend on the projects in the initial years to meet contractual commitments. If the capital is not spent a cash payment of the balance is required which does not qualify for cost recovery. The level of capital spend assumed in the value in use calculation is that expected over the period of the budget based on the current field development plans which assumes the minimum spend is met on each project and the contracts remain in force for the entire duration of the project.

Reserve volumes and production profiles: management has used its internally developed economic models of reserves and production as inputs into the value in use for the Production Enhancement, Risk Service and Production Sharing Contracts. Management has used an oil price of US$100 per barrel (2011: US$85 per barrel) to determine reserve volumes on Production Sharing Contracts.

Tariffs and payment terms: the tariffs and payment terms used in the value in use calculations for the Production Enhancement and Risk Service Contracts are those specified in the respective contracts with assumptions consistent with the current field development plan where KPI’s influence the payment terms.

Growth rate: estimates are based on management’s assessment of market share having regard to macro-economic factors and the growth rates experienced in the recent past in the markets in which the unit operates. A growth rate of 2.5% per annum has been applied for businesses within the Integrated Energy Services cash-generating unit where the cash flows are not based on long-term contractual arrangements.

Discount rate: management has used a pre-tax discount rate of 13.2% per annum (2011: 13.8% per annum). The discount rate is derived from the estimated weighted average cost of capital of the Group and has been calculated using an estimated risk free rate of return adjusted for the Group’s estimated equity market risk premium.

Sensitivity to changes in assumptions With regard to the assessment of value in use of the cash-generating units, management believes that no reasonably possible change in any of the above key assumptions would cause the carrying value of the relevant unit to exceed its recoverable amount, after giving due consideration to the macro-economic outlook for the oil and gas industry and the commercial arrangements with customers underpinning the cash flow forecasts for each of the units.

F-54 Notes to the consolidated financial statements continued For the year ended 31 December 2012

11 Intangible assets

2012 2011 US$m US$m Intangible oil and gas assets Cost: At 1 January ...... 103 69 Additions ...... 165 40 Transfer to costs ...... — (6) Net book value of intangible oil and gas assets at 31 December ...... 268 103 Other intangible assets Cost: At 1 January ...... 30 25 Additions on acquisition ...... 6 — Transfer from other non-current financial assets (note14) ...... 10 — Additions ...... 7 6 Disposals ...... — — Exchange difference ...... 1 (1) At 31 December ...... 54 30 Accumulated amortisation: At 1 January ...... (11) (8) Amortisation ...... (4) (3) Disposal ...... — — Exchange difference ...... — — At 31 December ...... (15) (11) Net book value of other intangible assets at 31 December ...... 39 19 Total intangible assets ...... 307 122

Intangible oil and gas assets Oil and gas assets (part of the Integrated Energy Services segment) additions above comprise largely US$149m (2011: US$39m) of capitalised expenditure on the Group’s assets in Malaysia.

There were investing cash outflows relating to capitalised intangible oil and gas assets of US$165m (2011: US$40m) in the current period arising from pre-development activities.

US$6m transfer in 2011 relates to a long-term receivable from a customer on the Berantai RSC contract being their share of development expenditure, which was transferred to costs.

Other intangible assets Other intangible asset additions on acquisition represent US$6m of e-learning software that formed part of the acquisition during the year of Oilennium Limited. Transfers from other non-current financial assets are transition costs relating to the Santuario, Magallanes and Ticleni Production Enhancement Contracts of US$10m (note 14).

Other intangible assets comprising project development expenditure, customer contracts, proprietary software, LNG intellectual property and patent technology are being amortised over their estimated economic useful life on a straight-line basis and the related amortisation charges included in selling, general and administration expenses (note 4c).

F-55 Notes to the consolidated financial statements continued For the year ended 31 December 2012

12 Investments in associates

2012 2011 US$m US$m Investment in Gateway Storage Company Limited ...... — 14 Associates acquired through acquisition of subsidiary ...... 1 1 Transfer from subsidiary to investment in associate – Petrofac FPF1 Limited ...... 9 — Investment in Seven Energy International Limited ...... 167 149 177 164

As a result of the disposal of 75.2% of Petrofac FPF1 Limited (see note 4f) the remaining 24.8% investment is classified as an associate recognised at a fair value of US$9m.

Gateway Storage Company Limited During the year the Group’s investment of US$14m, representing 20% of the equity of Gateway Storage Company Limited, has been written off in the consolidated income statement and the associated contingent consideration payable of US$7m (note 26) has also been reversed in the consolidated income statement due to continuing uncertainty over the future prospects for the company’s business.

Seven Energy International Limited On 25 November 2010, the Group invested US$100m for 15.0% (12.6% on a fully diluted basis) of the share capital of Seven Energy International Limited (Seven Energy), a leading Nigerian gas development and production company incurring US$1m of transaction costs. This investment which was previously held under available-for-sale financial assets was transferred to investments in associates, pursuant to an investment on 10 June 2011 of US$50m for an additional 4.6% of the share capital of Seven Energy which resulted in the Group being in a position to exercise significant influence over Seven Energy. On 30 October 2012, the Group invested US$25m for an additional 2.4% of the share capital of Seven Energy. The additional US$25m investment was made as part of a discounted rights issue required to deal with a short-term funding requirement by Seven Energy at a subscription price of US$150 per share and in light of this the carrying value of the investment has been tested for impairment and no impairment provision is required. No negative goodwill has been accounted for on the rights issue as the range of possible outcomes was immaterial. The Group also has the option to subscribe for 148,571 of additional warrants in Seven Energy at a cost of a further US$52m, subject to the performance of certain service provision conditions and milestones in relation to project execution. These warrants have been fair valued at 31 December 2012 as derivative financial instruments under IAS 39, using a Black Scholes Model, amounting to US$12m (2011: US$18m). US$6m (2011: US$6m other income) has been recognised as other expense in the current period income statement as a result of the revaluation of these derivatives at 31 December 2012 (note 4g). During 2012 deferred revenue recognised in trade and other payables of US$2m at 31 December 2012 was released in full to the consolidated income statement as 100% of the performance conditions required to subscribe for the remaining warrants in the Company were satisfied (2011: 80% satisfied with revenue recognised of US$10m).

The share of the associate’s statement of financial position is as follows:

2012 2011 US$m US$m Non-current assets ...... 163 93 Current assets ...... 22 22 Non-current liabilities ...... (56) (48) Current liabilities ...... (59) (11) Equity ...... 70 56 Transaction costs incurred ...... 2 2 Residual goodwill ...... 95 91 Carrying value of investment ...... 167 149 Share of associates revenues and net loss: Revenue ...... 23 24 Net loss ...... (8) (3)

F-56 Notes to the consolidated financial statements continued For the year ended 31 December 2012

13 Interest in joint ventures In the normal course of business, the Group establishes jointly controlled entities for the execution of certain of its operations and contracts. A list of these joint ventures is disclosed in note 32.

The Group’s share of assets, liabilities, revenues and expenses relating to jointly controlled entities is as follows:

2012 2011 US$m US$m Revenue ...... 266 453 Cost of sales ...... (195) (376) Gross profit ...... 71 77 Selling, general and administration expenses ...... (50) (50) Finance (expense)/income, net ...... (2) 1 Profit before income tax ...... 19 28 Income tax ...... (3) (1) Net profit ...... 16 27 Current assets ...... 95 172 Non-current assets ...... 256 183 Total assets ...... 351 355 Current liabilities ...... 133 272 Non-current liabilities ...... 184 57 Total liabilities ...... 317 329 Net assets ...... 34 26

14 Other financial assets

2012 2011 US$m US$m Other financial assets – non-current Long-term receivables from customers ...... 437 130 Restricted cash ...... 7 — Other ...... — 10 444 140 Other financial assets – current Short-term component of receivable from a customer 67 — Seven Energy warrants (note 12) ...... 12 18 Fair value of derivative instruments (note 31) ...... 2 9 Restricted cash ...... 4 2 Other ...... — 1 85 30

The long-term receivables from customers relate to the discounted value of amounts due under the Berantai RSC, which are being recovered over a six year period from 2013 in line with the contractual terms of the project and to amounts receivable in respect of the development of the Greater Stella Area.

Restricted cash comprises deposits with financial institutions securing various guarantees and performance bonds associated with the Group’s trading activities (note 29). This cash will be released on the maturity of these guarantees and performance bonds. Included in other non-current financial assets in 2011 are transition costs relating to the Santuario, Magallanes and Ticleni Production Enhancement Contracts which have been transferred to other intangible assets in 2012 (note 11).

F-57 Notes to the consolidated financial statements continued For the year ended 31 December 2012

15 Non-current asset held for sale

2012 2011 US$m US$m Non-current asset held for sale (note 9) ...... — 44 Liabilities directly associated with non-current asset held for sale ...... — 5

The non-current asset held for sale (part of the Integrated Energy Services segment) at 31 December 2011, comprising FPF1 Ltd was partly disposed of to the extent of 75.2%. The retained interest of 24.8% was recognised as an investment in associate at fair value (note 12).

16 Inventories

2012 2011 US$m US$m Crude oil ...... 3 4 Stores and spares ...... 23 6 Raw materials ...... 1 1 27 11

Included in the consolidated income statement are costs of inventories expensed of US$18m (2011: US$32m).

17 Work in progress and billings in excess of cost and estimated earnings

2012 2011 US$m US$m Cost and estimated earnings ...... 10,619 12,066 Less: billings ...... (9,963) (11,454) Work in progress ...... 656 612 Billings ...... 5,790 2,856 Less: cost and estimated earnings ...... (5,462) (2,467) Billings in excess of cost and estimated earnings ...... 328 389 Total cost and estimated earnings ...... 16,081 14,533 Total billings ...... 15,753 14,310

18 Trade and other receivables

2012 2011 US$m US$m Trade receivables ...... 1,227 869 Retentions receivable ...... 180 71 Advances ...... 144 216 Prepayments and deposits ...... 41 31 Receivables from joint venture partners ...... 268 131 Other receivables ...... 55 35 1,915 1,353

Other receivables mainly consist of Value Added Tax recoverable of US$46m (2011: US$8m) with the balance being miscellaneous non-trading receivables.

F-58 Notes to the consolidated financial statements continued For the year ended 31 December 2012

18 Trade and other receivables continued

Trade receivables are non-interest bearing and are generally on 30 to 60 days’ terms. Trade receivables are reported net of provision for impairment. The movements in the provision for impairment against trade receivables totalling US$1,227m (2011: US$869m) are as follows:

2012 2011 Specific General Specific General impairment impairment Total impairment impairment Total US$m US$m US$m US$m US$m US$m At 1 January ...... 213336 Charge for the year ...... —22——— Amounts written-off ...... — (2) (2) (1) (2) (3) At 31 December ...... 213213

At 31 December, the analysis of trade receivables is as follows:

Neither Number of days past due past due nor <30 31–60 61–90 91 – 120 121 – 360 > 360 impaired days days days days days days Total US$m US$m US$m US$m US$m US$m US$m US$m Unimpaired ...... 838 252 58 21 5 24 10 1,208 Impaired ...... — — — — 13 5 4 22 838 252 58 21 18 29 14 1,230 Less: impairment provision ...... — — — — (1) (1) (1) (3) Net trade receivables 2012 ...... 838 252 58 21 17 28 13 1,227 Unimpaired ...... 570 156 109 14 4 13 1 867 Impaired ...... — — — — 2 2 1 5 570 156 109 14 6 15 2 872 Less: impairment provision ...... — — — — — (2) (1) (3) Net trade receivables 2011 ...... 570 156 109 14 6 13 1 869

The credit quality of trade receivables that are neither past due nor impaired is assessed by management with reference to externally prepared customer credit reports and the historic payment track records of the counterparties.

Advances represent payments made to certain of the Group’s subcontractors for projects in progress, on which the related work had not been performed at the statement of financial position date. The decrease in advances during 2012 relates to the unwinding of advances on more mature contracts in the Onshore Engineering & Construction reporting segment.

Receivables from joint venture partners are amounts recoverable from venture partners on the Berantai FPSO, Block PM304 and Petrofac Emirates on an engineering, procurement and construction project.

All trade and other receivables are expected to be settled in cash.

Certain trade and other receivables will be settled in cash using currencies other than the reporting currency of the Group, and will be largely paid in sterling and euros.

19 Cash and short-term deposits

2012 2011 US$m US$m Cash at bank and in hand ...... 398 490 Short-term deposits ...... 216 1,082 Total cash and bank balances ...... 614 1,572

F-59 Notes to the consolidated financial statements continued For the year ended 31 December 2012

19 Cash and short-term deposits continued

Short-term deposits are made for varying periods of between one day and three months depending on the immediate cash requirements of the Group, and earn interest at respective short-term deposit rates. The fair value of cash and bank balances is US$614m (2011: US$1,572m).

For the purposes of the consolidated cash flow statement, cash and cash equivalents comprise the following:

2012 2011 US$m US$m Cash at bank and in hand ...... 398 490 Short-term deposits ...... 216 1,082 Bank overdrafts (note 24) ...... (57) (37) 557 1,535

20 Share capital The share capital of the Company as at 31 December was as follows:

2012 2011 US$m US$m Authorised 750,000,000 ordinary shares of US$0.020 each (2011: 750,000,000 ordinary shares of US$0.020 each) ...... 15 15 Issued and fully paid 345,891,490 ordinary shares of US$0.020 each (2011: 345,821,729 ordinary shares of US$0.020 each) ...... 7 7

The movement in the number of issued and fully paid ordinary shares is as follows:

Number Ordinary shares: Ordinary shares of US$0.020 each at 1 January 2011 ...... 345,715,053 Issued during the year as further contingent consideration payable for the acquisition of a subsidiary ...... 106,676 Ordinary shares of US$0.020 each at 1 January 2012 ...... 345,821,729 Issued during the year as further contingent consideration payable for the acquisition of a subsidiary ...... 69,761 Ordinary shares of US$0.020 each at 31 December 2012 ...... 345,891,490

The share capital comprises only one class of ordinary shares. The ordinary shares carry a voting right and the right to a dividend.

Share premium: The balance on the share premium account represents the amount received in excess of the nominal value of the ordinary shares.

Capital redemption reserve: The balance on the capital redemption reserve represents the aggregated nominal value of the ordinary shares repurchased and cancelled.

F-60 Notes to the consolidated financial statements continued For the year ended 31 December 2012

21 Treasury shares For the purpose of making awards under its employee share schemes, the Company acquires its own shares which are held by the Petrofac Employee Benefit Trust and the Petrofac Joint Venture Companies Employee Benefit Trust. All these shares have been classified in the statement of financial position as treasury shares within equity.

The movements in total treasury shares are shown below:

2012 2011 Number US$m Number US$m At 1 January ...... 5,736,017 75 6,757,339 65 Acquired during the year ...... 3,000,000 76 2,074,138 49 Vested during the year ...... (3,269,804) (51) (3,095,460) (39) At 31 December ...... 5,466,213 100 5,736,017 75

Shares vested during the year include dividend shares and 8% uplift adjustment made in respect of the EnQuest demerger of 375,040 shares (2011: 393,344 shares).

22 Share-based payment plans Performance Share Plan (PSP) Under the Company’s Performance Share Plan, share awards are granted to Executive Directors and a restricted number of other senior executives of the Group. The shares vest at the end of three years subject to continued employment and the achievement of certain pre-defined market and non-market-based performance conditions. The 50% market performance based part of these awards is dependent on the total shareholder return (TSR) of the Group, compared with an index composed of selected relevant companies. The fair value of the shares vesting under this portion of the award is determined by an independent valuer using a Monte Carlo simulation model taking into account the terms and conditions of the plan rules and using the following assumptions at the date of grant:

2012 2011 2010 2009 awards awards awards awards Expected share price volatility (based on median of comparator Group’s three-year volatilities) ...... 38.0% 51.0% 50.0% 49.0% Share price correlation with comparator Group ...... 46.0% 43.0% 39.0% 36.0% Risk-free interest rate ...... 0.4% 1.7% 1.50% 2.10% Expected life of share award ...... 3 years 3 years 3 years 3 years Fair value of TSR portion ...... 1,103p 788p 743p 456p

The non-market-based condition governing the vesting of the remaining 50% of the total award is subject to achieving between 10% and 20% earnings per share (EPS) growth targets over a three-year period. The fair values of the equity-settled award relating to the EPS part of the scheme are estimated, based on the quoted closing market price per Company share at the date of grant with an assumed vesting rate per annum built into the calculation (subsequently trued up at year end based on the actual leaver rate during the period from award date to year end) over the three-year vesting period of the plan.

Deferred Bonus Share Plan (DBSP) Under the DBSP selected employees are required to defer a proportion of their annual cash bonus into Company shares (‘Invested Award’). Following such an award, the Company will generally grant the participant an additional award of a number of shares bearing a specified ratio to the number of his or her invested shares (‘Matching Shares’), typically using a 1:1 ratio. Subject to a participant’s continued employment, invested and matching share awards may either vest 100% on the third anniversary of grant; or alternatively, vest one-third on the first anniversary of the grant, one-third on the second anniversary and the final proportion on the third anniversary.

F-61 Notes to the consolidated financial statements continued For the year ended 31 December 2012

22 Share-based payment plans continued

At the year end the values of the bonuses settled by shares cannot be determined until the Remuneration Committee has approved the portion of the employee bonuses to be settled in shares. Once the portion of the bonus to be settled in shares is determined, the final bonus liability to be settled in shares is transferred to the reserve for share-based payments. The costs relating to the Matching Shares are recognised over the corresponding vesting period and the fair values of the equity-settled Matching Shares granted to employees are based on the quoted closing market price at the date of grant with the charge adjusted to reflect the expected vesting rate of the plan.

Share Incentive Plan (SIP) All UK employees, including UK Executive Directors, are eligible to participate in the SIP. Employees may invest up to sterling £1,500 per tax year of gross salary (or, if lower, 10% of salary) to purchase ordinary shares in the Company. There is no holding period for these shares.

Restricted Share Plan (RSP) Under the RSP, selected employees are made grants of shares on an ad hoc basis. The RSP is used primarily, but not exclusively, to make awards to individuals who join the Group part way through the year, having left accrued benefits with a previous employer. The fair values of the awards granted under the RSP at various grant dates during the year are based on the quoted market price at the date of grant adjusted for an assumed vesting rate over the relevant vesting period.

Value Creation Plan (VCP) During 2012 the Company introduced a new one-off Value Creation Plan (VCP) which is a share option scheme for Executive Directors and key senior executives within the Company. The VCP is a premium priced share option scheme with options granted with an exercise price set at a 10% premium to the grant date price. Options will vest to the extent of satisfying Group and divisional profit after tax targets, together with various other performance underpins and risk/malus provisions that can be imposed at the discretion of the Remuneration Committee of the Board. The share options vest in equal tranches on the fourth, fifth and sixth anniversaries of the original grant date but may be exercised up to eight years from the date of grant.

The VCP share options were fair valued by an independent valuer using a Black-Scholes option pricing model taking into account the rules of the plan and using the following key assumptions:

Tranche 1 Tranche 2 Tranche 3 Share price at the date of grant ...... 1,555p 1,555p 1,555p Exercise price ...... 1,710p 1,710p 1,710p Expected lives of the award ...... 6 years 6.5 years 7 years Share price volatility ...... 41% 41% 41% Share price dividend yield ...... 2.3% 2.3% 2.3% Risk-free interest rates ...... 1.1% 1.2% 1.3% Per share fair values ...... 451p 467p 482p

Share-based payment plans information The details of the fair values and assumed vesting rates of the share-based payment plans are below:

PSP (EPS portion) DBSP RSP Fair value per Assumed Fair value per Assumed Fair value per Assumed share vesting rate share vesting rate share vesting rate 2012 awards ...... 1,705p 97.0% 1,705p 94.6% 1,555p 89.0% 2011 awards ...... 1,426p 94.3% 1,426p 91.3% 1,463p 90.2% 2010 awards ...... 1,103p 93.8% 1,185p 87.5% 990p 90.5% 2009 awards ...... 545p 93.1% 545p 91.3% 430p 70.0%

F-62 Notes to the consolidated financial statements continued For the year ended 31 December 2012

22 Share-based payment plans continued

The following table shows the movements in the number of shares held under the share-based payment plans outstanding but not exercisable:

PSP DBSP RSP Total VCP 2012 2011 2012 2011 2012 2011 2012 2012 2011 Number Number Number Number Number Number Number Number Number Outstanding at 1 January ....1,358,046 1,350,189 3,809,746 4,082,311 534,780 1,003,712 — 5,702,572 6,436,212 Granted during the year ..... 409,212 482,379 1,507,614 1,538,252 227,726 204,402 1,773,713 3,918,265 2,225,033 Vested during the year ...... (535,072) (421,309) (1,991,385) (1,681,130) (210,836) (664,512) — (2,737,293) (2,766,951) Forfeited during the year .... — (53,213) (205,007) (129,687) (29,499) (8,822) — (234,506) (191,722) Outstanding at 31 December ...... 1,232,186 1,358,046 3,120,968 3,809,746 522,171 534,780 1,773,713 6,649,038 5,702,572

* Includes Invested and Matching Shares.

The number of shares still outstanding but not exercisable at 31 December 2012, for each award is as follows:

PSP DBSP RSP Total VCP 2012 2011 2012 2011 2012 2011 2012 2012 2011 Number Number Number Number Number Number Number Number Number 2012 awards ...... 409,212 — 1,421,132 — 222,056 — 1,773,713 3,826,113 — 2011 awards ...... 454,969 454,969 1,049,174 1,491,298 138,135 204,402 — 1,642,278 2,150,669 2010 awards ...... 368,005 368,005 650,662 984,496 161,980 186,758 — 1,180,647 1,539,259 2009 awards ...... — 535,072 — 1,333,952 — 36,658 ——1,905,682 2008 awards ...... — — — — — 1,030 ——1,030 2007 awards ...... — — — — — 105,932 ——105,932 Total awards ...... 1,232,186 1,358,046 3,120,968 3,809,746 522,171 534,780 1,773,713 6,649,038 5,702,572

The weighted average share price of the Company shares during 2012 was US$24.91 (sterling equivalent of £15.70).

The number of outstanding shares excludes the 8% uplift adjustment made in respect of the EnQuest demerger and dividend shares shown below:

PSP DBSP RSP Total 2012 2011 2012 2011 2012 2011 2012 2011 Number Number *Number *Number Number Number Number Number EnQuest 8% uplift ...... — 47,335 52,037 188,177 4,542 27,982 56,579 263,494 Dividend shares ...... 55,511 68,073 119,699 158,691 14,058 27,090 189,268 253,854 Outstanding at 31 December . . 55,511 115,408 171,736 346,868 18,600 55,072 245,847 517,348

The charge in respect of share-based payment plans recognised in the consolidated income statement is as follows:

PSP *DBSP RSP VCP Total 2012 2011 2012 2011 2012 2011 2012 2011 2012 2011 US$m US$m US$m US$m US$m US$m US$m US$m US$m US$m Share based payment charge ...... 6 6 15 13 4 4 1 — 26 23

* Represents charge on Matching Shares only.

F-63 Notes to the consolidated financial statements continued For the year ended 31 December 2012

22 Share-based payment plans continued

The Group has recognised a total charge of US$26m (2011: US$23m) in the consolidated income statement during the year relating to the above employee share-based schemes (see note 4d) which has been transferred to the reserve for share-based payments along with US$20m of the bonus liability accrued for the year ended 31 December 2011 which has been settled in shares granted during the year (2011: US$18m).

For further details on the above employee share-based payment schemes refer to pages 92, 96 and 99 to 103 of the Directors’ Remuneration report.

23 Other reserves

Net unrealised Foreign Reserve for gains/(losses) currency share-based on derivatives translation payments Total US$m US$m US$m US$m Balance at 1 January 2011 ...... (3) (19) 57 35 Foreign currency translation (losses) ...... — (16) — (16) Net (gains) on maturity of cash flow hedges recycled in the year ...... (3) — — (3) Net fair value losses on derivatives and financial assets designated as cash flow hedges ...... (14) — — (14) Share-based payments charge (note 22) ...... — — 23 23 Transfer during the year (note 22) ...... — — 18 18 Shares vested during the year ...... — — (34) (34) Deferred tax on share-based payments reserve ...... — — (3) (3) Balance at 1 January 2012 ...... (20) (35) 61 6 Foreign currency translation ...... — 10 — 10 Net losses on maturity of cash flow hedges recycled in the year . . . 20 — — 20 Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... — — — — Share-based payments charge (note 22) ...... — — 26 26 Transfer during the year (note 22) ...... — — 20 20 Shares vested during the year ...... — — (45) (45) Deferred tax on share-based payments reserve ...... — — 1 1 Balance at 31 December 2012 ...... — (25) 63 38

Nature and purpose of other reserves Net unrealised gains/(losses) on derivatives The portion of gains or losses on cash flow hedging instruments that are determined to be effective hedges is included within this reserve net of related deferred tax effects. When the hedged transaction occurs or is no longer forecast to occur, the gain or loss is transferred out of equity to the consolidated income statement. Realised net losses amounting to US$20m (2011: US$3m net gain) relating to foreign currency forward contracts and financial assets designated as cash flow hedges have been recognised in cost of sales.

The forward currency points element and ineffective portion of derivative financial instruments relating to forward currency contracts and gains on un-designated derivatives amounting to a net loss of US$2m (2011: US$6m loss) have been recognised in the cost of sales.

Foreign currency translation reserve The foreign currency translation reserve is used to record exchange differences arising from the translation of the financial statements in foreign subsidiaries. It is also used to record exchange differences arising on monetary items that form part of the Group’s net investment in subsidiaries.

F-64 Notes to the consolidated financial statements continued For the year ended 31 December 2012

23 Other reserves continued

Reserve for share-based payments The reserve for share-based payments is used to record the value of equity-settled share-based payments awarded to employees and transfers out of this reserve are made upon vesting of the original share awards.

The transfer during the year reflects the transfer from accrued expenses within trade and other payables of the bonus liability relating to the year ended 2011 of US$20m (2010 bonus of US$18m) which has been voluntarily elected or mandatorily obliged to be settled in shares during the year (note 22).

24 Interest-bearing loans and borrowings The Group had the following interest-bearing loans and borrowings outstanding:

31 December 2012 31 December 2011 Actual interest rate Actual interest rate Effective interest 2012 2011 % % rate % Maturity US$m US$m Current Bank overdrafts (i) UK LIBOR + 1.50% UK LIBOR + 1.50% UK LIBOR on demand 57 37 US LIBOR + 1.50% US LIBOR + 1.50% + 1.50% US LIBOR + 1.50% Other loans: Current portion of term (iii) — US/UK LIBOR + n/a n/a — 17 loan 0.875% (2011: 3.16% to 3.96%) Current portion of term (iv) — US/UK LIBOR n/a n/a — 7 loan + 0.875% (2011: 1.67% to 3.55%) 57 61 Non-current Revolving credit facility (ii) US LIBOR + 1.50% — US LIBOR + 5 years 303 — 1.50% Term loan (iii) — US/UK LIBOR + n/a n/a — 12 0.875% (2011: 3.16% to 3.96%) Term loan (iv) — US/UK LIBOR + n/a n/a — 7 0.875% (2011: 1.67% to 3.55%) 303 19 Less: Debt acquisition costs net of accumulated amortisation and effective interest rate adjustments (11) (3) 292 16

F-65 Notes to the consolidated financial statements continued For the year ended 31 December 2012

24 Interest-bearing loans and borrowings continued

Details of the Group’s interest-bearing loans and borrowings are as follows:

(i) Bank overdrafts Bank overdrafts are drawn down in US dollars and sterling denominations to meet the Group’s working capital requirements. These are repayable on demand.

(ii) Revolving Credit Facility On 11 September 2012, Petrofac entered into a US$1,200m five year committed revolving credit facility with a syndicate of 13 international banks, which is available for general corporate purposes. The facility, which matures on 11 September 2017, is unsecured and is subject to two financial covenants relating to leverage and interest cover. Petrofac was in compliance with these covenants for the year ending 31 December 2012. As at 31 December 2012, US$303m was drawn under this facility.

Interest is payable on the drawn balance of the facility at LIBOR + 1.5% and in addition utilisation fees are payable depending on the level of utilisation.

(iii) Term loan The loan was repaid in full during 2012 and no amounts were drawn during the year (2011: drawings of US$15m denominated in US dollars and US$15m denominated in sterling).

(iv) Term loan The loan was repaid in full during 2012 and no amounts were drawn during the year (2011: drawings of US$10m denominated in US dollars and US$4m denominated in sterling).

The Group’s credit facilities contain covenants relating to interest and net borrowings cover. None of the Company’s subsidiaries are subject to any material restrictions on their ability to transfer funds in the form of cash dividends, loans or advances to the Company.

25 Provisions

Other long-term employment benefits Provision for Other provision decommissioning provisions Total US$m US$m US$m US$m At 1 January 2012 ...... 51 6 3 60 Additions during the year ...... 19 27 1 47 Paid in the year ...... (8) (1) — (9) Unwinding of discount ...... 1 1 — 2 At 31 December 2012 ...... 63 33 4 100

F-66 Notes to the consolidated financial statements continued For the year ended 31 December 2012

25 Provisions continued

Other long-term employment benefits provision Labour laws in the United Arab Emirates require employers to provide for other long-term employment benefits. These benefits are payable to employees on being transferred to another jurisdiction or on cessation of employment based on their final salary and number of years’ service. All amounts are unfunded. The long-term employment benefits provision is based on an internally produced end of service benefits valuation model with the key underlying assumptions being as follows:

Senior Other employees employees Average number of years of future service ...... 5 3 Average annual % salary increases ...... 6% 4% Discount factor ...... 5% 5%

Senior employees are those earning a base of salary of over US$96,000 per annum.

Discount factor used is the local Dubai five-year Sukuk rate.

Provision for decommissioning The decommissioning provision primarily relates to the Group’s obligation for the removal of facilities and restoration of the sites at the PM304 field in Malaysia, Chergui in Tunisia and Santuario and Magallanes Production Enhancement Contracts in Mexico. The liability is discounted at the rate of 4.16% on PM304 (2011: 4.16%), 5.25% on Chergui (2011: 5.25%) and 5.38% on Santuario and Magallanes Production Enhancement Contracts (2011: n/a). The unwinding of the discount is classified as finance cost (note 5). The Group estimates that the cash outflows against these provisions will arise in 2026 on PM304, 2018 on Chergui and 2029 on Santuario and Magallanes Production Enhancement Contracts.

Other provisions This represents amounts set aside to cover claims against the Group which will be settled via the captive insurance company Jermyn Insurance Company Limited.

26 Other financial liabilities

2012 2011 US$m US$m Other financial liabilities – non-current Contingent consideration payable ...... 1 13 Finance lease creditors (note 29) ...... 6 11 Fair value of derivative instruments (note 31) ...... 1 — Other ...... — — 8 24 Other financial liabilities – current Contingent consideration payable ...... 7 3 Fair value of derivative instruments (note 31) ...... 3 23 Finance lease creditors (note 29) ...... 7 5 Other ...... — 1 17 32

Contingent consideration payable to the Group’s investment in Gateway Storage Company Limited of US$7m (note 12) has been reversed during the year.

F-67 Notes to the consolidated financial statements continued For the year ended 31 December 2012

27 Trade and other payables

2012 2011 US$m US$m Trade payables ...... 862 477 Advances received from customers ...... 373 770 Accrued expenses ...... 601 415 Other taxes payable ...... 40 24 Other payables ...... 105 56 1,981 1,742

Advances from customers represent payments received for contracts on which the related work had not been performed at the statement of financial position date.

Other payables mainly consist of retentions held against subcontractors of US$86m (2011: US$29m).

Certain trade and other payables will be settled in currencies other than the reporting currency of the Group, mainly in sterling, euros and Kuwaiti dinars.

28 Accrued contract expenses

2012 2011 US$m US$m Accrued contract expenses ...... 743 1,269

29 Commitments and contingencies Commitments In the normal course of business the Group will obtain surety bonds, letters of credit and guarantees, which are contractually required to secure performance, advance payment or in lieu of retentions being withheld. Some of these facilities are secured by issue of corporate guarantees by the Company in favour of the issuing banks.

At 31 December 2012, the Group had letters of credit of US$ nil (2011: US$6m) and outstanding letters of guarantee, including performance, advance payments and bid bonds of US$2,296m (2011: US$2,185m) against which the Group had pledged or restricted cash balances of, in aggregate, US$11m (2011: US$2m).

At 31 December 2012, the Group had outstanding forward exchange contracts amounting to US$228m (2011: US$324m). These commitments consist of future obligations either to acquire or to sell designated amounts of foreign currency at agreed rates and value dates (note 31).

Leases The Group has financial commitments in respect of non-cancellable operating leases for office space and equipment. These non-cancellable leases have remaining non-cancellable lease terms of between one and 17 years and, for certain property leases, are subject to renegotiation at various intervals as specified in the lease agreements. The future minimum rental commitments under these non-cancellable leases are as follows:

2012 2011 US$m US$m Within one year ...... 25 24 After one year but not more than five years ...... 108 45 More than five years ...... 198 49 331 118

F-68 Notes to the consolidated financial statements continued For the year ended 31 December 2012

29 Commitments and contingencies continued

Included in the above are commitments relating to the leasing of an FPSO for the Cendor Phase 2 project of US$149m (2011: US$ nil) and the lease of office buildings in Aberdeen, United Kingdom of US$127m (2011: US$34m).

Minimum lease payments recognised as an operating lease expense during the year amounted to US$37m (2011: US$37m).

Long-term finance lease commitments are as follows:

Future minimum lease Present payments Finance cost value US$m US$m US$m Land, buildings and leasehold improvements ...... 14 1 13 The commitments are as follows: Within one year ...... 8 1 7 After one year but not more than five years ...... 6 — 6 More than five years ...... — — — 14 1 13

Capital commitments At 31 December 2012, the Group had capital commitments of US$493m (2011: US$480m) excluding the above lease commitments.

Included in the US$493m of commitments are:

2012 2011 US$m US$m Production Enhancement Contracts in Mexico ...... 146 225 Costs to refurbish the Berantai FPSO in Malaysia ...... — 89 Further appraisal and development of wells as part of Block PM304 in Malaysia ...... 287 111 Costs in respect of Ithaca Greater Stella Field development in the North Sea ...... 50 — Production Enhancement Contract on the Ticleni field in Romania ...... — 25 Commitments in respect of the construction of a new office building in United Arab Emirates ...... 5 21

30 Related party transactions The consolidated financial statements include the financial statements of Petrofac Limited and the subsidiaries listed in note 32. Petrofac Limited is the ultimate parent entity of the Group.

The following table provides the total amount of transactions which have been entered into with related parties:

Purchases Amounts Amounts Sales to from owed by owed to related related related related parties parties parties parties US$m US$m US$m US$m Joint ventures ...... 2012 170 135 5 38 2011 323 187 95 23 Associates ...... 2012 3 — 17 — 2011 14 — 4 — Key management personnel interests ...... 2012 — 2 — — 2011 — 2 — —

F-69 Notes to the consolidated financial statements continued For the year ended 31 December 2012

30 Related party transactions continued

All sales to and purchases from joint ventures are made at normal market prices and the pricing policies and terms of these transactions are approved by the Group’s management.

All related party balances will be settled in cash.

Purchases in respect of key management personnel interests of US$1,521,000 (2011: US$1,411,000) reflect the costs of chartering the services of an aeroplane used for the transport of senior management and Directors of the Group on company business, which is owned by an offshore trust of which the Group Chief Executive of the Company is a beneficiary. The charter rates charged for Group usage of the aeroplane are significantly less than comparable market rates.

Also included in purchases in respect of key management personnel interests is US$189,000 (2011: US$180,000) relating to client entertainment provided by a business owned by a member of the Group’s key management.

For details of the rights issue by Seven Energy and the warrants held see note 12 to the financial statements.

Compensation of key management personnel The following details remuneration of key management personnel of the Group comprising Executive and Non- executive Directors of the Company and other senior personnel. Further information relating to the individual Directors is provided in the Directors’ remuneration report on pages 88 to 103.

2012 2011 US$m US$m Short-term employee benefits ...... 21 20 Share-based payments ...... 8 8 Fees paid to Non-executive Directors ...... 1 1 30 29

31 Risk management and financial instruments Risk management objectives and policies The Group’s principal financial assets and liabilities, other than derivatives, comprise available-for-sale financial assets, trade and other receivables, amounts due from/to related parties, cash and short-term deposits, work-in- progress, interest-bearing loans and borrowings, trade and other payables and contingent consideration.

The Group’s activities expose it to various financial risks particularly associated with interest rate risk on its variable rate cash and short-term deposits, loans and borrowings and foreign currency risk on both conducting business in currencies other than reporting currency as well as translation of the assets and liabilities of foreign operations to the reporting currency. These risks are managed from time to time by using a combination of various derivative instruments, principally forward currency contracts in line with the Group’s hedging policies. The Group has a policy not to enter into speculative trading of financial derivatives.

The Board of Directors of the Company has established an Audit Committee and Board Risk Committee to help identify, evaluate and manage the significant financial risks faced by the Group and their activities are discussed in detail on pages 78 to 87.

The other main risks besides interest rate and foreign currency risk arising from the Group’s financial instruments are credit risk, liquidity risk and commodity price risk and the policies relating to these risks are discussed in detail below:

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.

F-70 Notes to the consolidated financial statements continued For the year ended 31 December 2012

31 Risk management and financial instruments continued

The Group’s exposure to market risk arising from changes in interest rates relates primarily to the Group’s long- term variable rate debt obligations and its cash and bank balances. The Group’s policy is to manage its interest cost using a mix of fixed and variable rate debt. The Group’s cash and bank balances are at floating rates of interest.

Interest rate sensitivity analysis The impact on the Group’s pre-tax profit and equity due to a reasonably possible change in interest rates on loans and borrowings at the reporting date is demonstrated in the table below. The analysis assumes that all other variables remain constant.

Pre-tax profit Equity 100 basis 100 basis 100 basis 100 basis point point point point increase decrease increase decrease US$m US$m US$m US$m 31 December 2012 ...... (2) 2 — — 31 December 2011 ...... (1) 1 — —

The following table reflects the maturity profile of these financial liabilities and assets:

Year ended 31 December 2012

Within 1–2 2–3 3–4 4–5 More than 1 year years years years years 5 years Total US$m US$m US$m US$m US$m US$m US$m Financial liabilities Floating rates Bank overdrafts (note 24) ...... 57———— — 57 Term loans (note 24) ...... — — — — 303 — 303 57 — — — 303 — 360 Financial assets Floating rates Cash and short-term deposits (note 19) ...... 614 — — — — — 614 Restricted cash balances (note 14) ...... 4 7——— — 11 618 7 — — — — 625

Year ended 31 December 2011

Within 1–2 2–3 3–4 4–5 More than 1 year years years years years 5 years Total US$m US$m US$m US$m US$m US$m US$m Financial liabilities Floating rates Bank overdrafts (note 24) ...... 37 ———— — 37 Term loans (note 24) ...... 24 19 — — — — 43 61 19 — — — — 80 Financial assets Floating rates Cash and short-term deposits (note 19) ...... 1,572 ———— — 1,572 Restricted cash balances (note 14) ...... 2 ———— — 2 1,574 ———— — 1,574

F-71 Notes to the consolidated financial statements continued For the year ended 31 December 2012

31 Risk management and financial instruments continued

Financial liabilities in the above table are disclosed gross of debt acquisition costs and effective interest rate adjustments of US$11m (2011: US$3m).

Interest on financial instruments classified as floating rate is re-priced at intervals of less than one year. The other financial instruments of the Group that are not included in the above tables are non-interest bearing and are therefore not subject to interest rate risk.

Foreign currency risk The Group is exposed to foreign currency risk on sales, purchases, and translation of assets and liabilities that are in a currency other than the functional currency of its operating units. The Group is also exposed to the translation of the functional currencies of its units to the US dollar reporting currency of the Group. The following table summarises the percentage of foreign currency denominated revenues, costs, financial assets and financial liabilities, expressed in US dollar terms, of the Group totals.

2012 2011 % of foreign % of foreign currency currency denominated denominated items items Revenues ...... 34.5% 36.4% Costs ...... 54.7% 57.7% Current financial assets ...... 37.8% 32.5% Non-current financial assets ...... 0.0% 0.0% Current financial liabilities ...... 33.9% 34.7% Non-current financial liabilities ...... 2.7% 54.2%

The Group uses forward currency contracts to manage the currency exposure on transactions significant to its operations. It is the Group’s policy not to enter into forward contracts until a highly probable forecast transaction is in place and to negotiate the terms of the derivative instruments used for hedging to match the terms of the hedged item to maximise hedge effectiveness.

Foreign currency sensitivity analysis The income statements of foreign operations are translated into the reporting currency using a weighted average exchange rate of conversion. Foreign currency monetary items are translated using the closing rate at the reporting date. Revenues and costs in currencies other than the functional currency of an operating unit are recorded at the prevailing rate at the date of the transaction. The following significant exchange rates applied during the year in relation to US dollars:

2012 2011 Average Closing Average Closing rate rate rate rate Sterling ...... 1.59 1.63 1.60 1.55 Kuwaiti dinar ...... 3.57 3.55 3.62 3.59 Euro ...... 1.29 1.32 1.40 1.30

The following table summarises the impact on the Group’s pre-tax profit and equity (due to change in the fair value of monetary assets, liabilities and derivative instruments) of a reasonably possible change in US dollar exchange rates with respect to different currencies:

Pre-tax profit Equity +10% US –10% US +10% US –10% US dollar rate dollar rate dollar rate dollar rate increase decrease increase decrease US$m US$m US$m US$m 31 December 2012 ...... (10) 10 19 (19) 31 December 2011 ...... (4) 4 50 (50)

F-72 Notes to the consolidated financial statements continued For the year ended 31 December 2012

31 Risk management and financial instruments continued

Derivative instruments designated as cash flow hedges At 31 December 2012, the Group had foreign exchange forward contracts as follows:

Fair value Fair value Net unrealised Contract value (undesignated) (designated) gain/(loss) 2012 2011 2012 2011 2012 2011 2012 2011 US$m US$m US$m US$m US$m US$m US$m US$m Euro purchases ...... 67 223 — — — (10) — (8) Sterling (sales) purchases ...... (103) 40 (2) — — (2) — (1) Yen (sales) ...... (4) (4) — — — — — — Singapore dollar purchases ...... — 46 — — — (1) — (1) (2) — — (13) — (10)

The above foreign exchange contracts mature and will affect income between January 2013 and July 2014 (2011: between January 2012 and July 2013).

At 31 December 2012, the Group had cash and short-term deposits designated as cash flow hedges with net unrealised gains/(losses) of US$ nil (2011: US$9m loss) as follows:

Net unrealised Fair value gain/(loss) 2012 2011 2012 2011 US$m US$m US$m US$m Euro cash and short-term deposits ...... 118 181 — (9) Sterling cash and short-term deposits ...... 7 15 — — Yen cash and short-term deposits ...... 1 3 — — Swiss francs cash and short-term deposits ...... — — — — — (9)

During 2012, changes in fair value gains of US$2m (2011: losses US$14m) relating to these derivative instruments and financial assets were taken to equity and US$18m of losses (2011: US$3m gains) were recycled from equity into cost of sales in the income statement. The forward points and ineffective portions of the above foreign exchange forward contracts and loss on un-designated derivatives of US$2m (2011: US$6m loss) were recognised in the income statement (note 4b).

Commodity price risk – oil prices The Group is exposed to the impact of changes in oil and gas prices on its revenues and profits generated from sales of crude oil and gas. The Group’s policy is to manage its exposure to the impact of changes in oil and gas prices using derivative instruments, primarily swaps and collars. Hedging is only undertaken once sufficiently reliable and regular long-term forecast production data is available.

During the year the Group entered into various crude oil swaps and zero cost collars hedging oil production of 1,000,000 barrels (bbl) (2011: 163,766 bbl) with maturities ranging from January 2013 to December 2013. In addition, fuel oil swaps were also entered into for hedging gas production of 31,743 metric tonnes (MT) (2011: 21,100MT) with maturities from January 2013 to September 2013.

The fair value of oil derivatives at 31 December 2012 was US$ nil (2011: US$1m liability) with net unrealised losses deferred in equity of US$ nil (2011 US$ nil). During the year, losses of US$2m (2011: US$ nil loss) were recycled from equity into the consolidated income statement on the occurrence of the hedged transactions and a loss in the fair value recognised in equity of US$2m (2011: US$ nil).

F-73 Notes to the consolidated financial statements continued For the year ended 31 December 2012

31 Risk management and financial instruments continued

The following table summarises the impact on the Group’s pre-tax profit and equity (due to a change in the fair value of oil derivative instruments and the underlifting asset/overlifting liability) of a reasonably possible change in the oil price:

Pre-tax profit Equity +10 –10 +10 –10 US$/bbl US$/bbl US$/bbl US$/bbl increase decrease increase decrease US$m US$m US$m US$m 31 December 2012 ...... — — (12) 12 31 December 2011 ...... (1) 1 (2) 2

Credit risk The Group trades only with recognised, creditworthy third parties. Business Unit Risk Review Committees (BURRC) evaluates the creditworthiness of each individual third-party at the time of entering into new contracts. Limits have been placed on the approval authority of the BURRC above which the approval of the Board of Directors of the Company is required. Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary. At 31 December 2012, the Group’s five largest customers accounted for 48.8% of outstanding trade receivables and work in progress (2011: 47.1%).

With respect to credit risk arising from the other financial assets of the Group, which comprise cash and cash equivalents, available-for-sale financial assets and certain derivative instruments, the Group’s exposure to credit risk arises from default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments.

Liquidity risk The Group’s primary objective is to ensure sufficient liquidity is available to support future growth. Our strategy includes the provision of financial capital and the potential impact on the Group’s capital structure is reviewed regularly. The Group is not exposed to any external capital constraints. The maturity profiles of the Group’s financial liabilities at 31 December 2012 are as follows:

Year ended 31 December 2012

Contractual 6 months 6–12 1–2 2–5 More than undiscounted Carrying or less months years years 5 years cash flows amount US$m US$m US$m US$m US$m US$m US$m Financial liabilities Interest-bearing loans and borrowings .... 57 — — 303 — 360 349 Finance lease creditors ...... —86—— 1413 Trade and other payables (excluding advances from customers and other taxes payable) ...... 1,464 104 — — — 1,568 1,568 Due to related parties ...... 38 — — — — 38 38 Contingent consideration ...... 162—— 9 8 Derivative instruments ...... 3— 1— — 4 4 Interest payments ...... 4366— 19— 1,567 121 15 309 — 2,012 1,980

F-74 Notes to the consolidated financial statements continued For the year ended 31 December 2012

31 Risk management and financial instruments continued

Year ended 31 December 2011

Contractual 6 months 6–12 1–2 2–5 More than undiscounted Carrying or less months years years 5 years cash flows amount US$m US$m US$m US$m US$m US$m US$m Financial liabilities Interest-bearing loans and borrowings .... 48 12 20 — — 80 77 Finance lease creditors ...... — 6 11 — — 17 16 Trade and other payables (excluding advances from customers and other taxes payable) ...... 932 16 — — — 948 948 Due to related parties ...... 23 — — — — 23 23 Contingent consideration ...... 2 2 13 — — 17 16 Derivative instruments ...... 20 3 — — — 23 23 1,025 39 44 — — 1,108 1,103

The Group uses various funded facilities provided by banks and its own financial assets to fund the above mentioned financial liabilities.

Capital management The Group’s policy is to maintain a healthy capital base to sustain future growth and maximise shareholder value.

The Group seeks to optimise shareholder returns by maintaining a balance between debt and capital and monitors the efficiency of its capital structure on a regular basis. The gearing ratio and return on shareholders’ equity is as follows:

2012 2011 US$m US$m Cash and short-term deposits ...... 614 1,572 Interest-bearing loans and borrowings (A) ...... (349) (77) Net cash (B) ...... 265 1,495 Equity attributable to Petrofac Limited shareholders (C) ...... 1,549 1,112 Profit for the year attributable to Petrofac Limited shareholders (D) ...... 632 540 Gross gearing ratio (A/C) ...... 22.5% 6.9% Net gearing ratio (B/C) ...... Net cash Net cash position position Shareholders’ return on investment (D/C) ...... 40.8% 48.6%

F-75 Notes to the consolidated financial statements continued For the year ended 31 December 2012

31 Risk management and financial instruments continued

Fair values of financial assets and liabilities The fair value of the Group’s financial instruments and their carrying amounts included within the Group’s statement of financial position are set out below:

Carrying amount Fair value 2012 2011 2012 2011 US$m US$m US$m US$m Financial assets Cash and short-term deposits ...... 614 1,572 614 1,572 Restricted cash ...... 11 2 11 2 Seven Energy warrants ...... 12 18 12 18 Forward currency contracts – designated as cash flow hedge ...... 1 9 1 9 Forward currency contracts – undesignated ...... 1 — 1 — Financial liabilities Interest-bearing loans and borrowings ...... 349 77 360 80 Contingent consideration ...... 8 16 8 16 Oil derivative ...... — 1 — 1 Forward currency contracts – designated as cash flow hedge ...... 1 22 1 22 Forward currency contracts – undesignated ...... 3 — 3 —

Fair values of financial assets and liabilities Market values have been used to determine the fair values of available-for-sale financial assets, forward currency contracts and oil derivatives. The fair value of warrants over equity instruments in Seven Energy has been calculated using a Black Scholes option valuation model (note 12). The fair values of long-term interest-bearing loans and borrowings are equivalent to their amortised costs determined as the present value of discounted future cash flows using the effective interest rate. The Company considers that the carrying amounts of trade and other receivables, work-in-progress, trade and other payables, other current and non-current financial assets and liabilities approximate their fair values and are therefore excluded from the above table.

Fair value hierarchy The following financial instruments are measured at fair value using the hierarchy below for determination and disclosure of their respective fair values: Tier 1: Unadjusted quoted prices in active markets for identical financial assets or liabilities Tier 2: Other valuation techniques where the inputs are based on all observation data (directly or indirectly) Tier 3: Other valuation techniques where the inputs are based on unobservable market data

Year ended 31 December 2012

Tier 2 Tier 3 US$m US$m Financial assets Seven Energy warrants ...... —12 Forward currency contracts – designated as cash flow hedge ...... 1— Forward currency contracts – undesignated ...... 1— Financial liabilities Forward currency contracts – designated as cash flow hedge ...... 1— Forward currency contracts – undesignated ...... 3—

F-76 Notes to the consolidated financial statements continued For the year ended 31 December 2012

31 Risk management and financial instruments continued

Year ended 31 December 2011

Tier 2 US$m Financial assets Seven Energy warrants ...... 18 Forward currency contracts – designated as cash flow hedge ...... 9 Forward currency contracts – undesignated ...... — Financial liabilities Forward currency contracts – designated as cash flow hedge ...... 21 Forward currency contracts – undesignated ...... 1 Oil derivative ...... 1

32 Principal subsidiaries and joint ventures At 31 December 2012, the Group had investments in the following subsidiaries and incorporated joint ventures:

Proportion of nominal value of issued shares controlled by the Group Name of company Country of incorporation 2012 2011 Trading subsidiaries Petrofac Algeria EURL ...... Algeria 100 100 Petrofac (Cyprus) Limited ...... Cyprus 100 100

CO2DeepStore (Aspen) Limited ...... England 100 100 Eclipse Petroleum Technology Limited ...... England 100 100 K W Limited ...... England 100 — Oilennium Limited ...... England 100 — Petrofac (Malaysia-PM304) Limited ...... England 100 100 Petrofac Contracting Limited ...... England 100 — Petrofac Engineering Limited ...... England 100 100 Petrofac Services Limited ...... England *100 *100 Petrofac UK Holdings Limited ...... England *100 *100 The New Energy Industries Limited ...... England 100 100 TNEI Services Limited ...... England 100 100 Caltec Limited ...... England 100 100 Petrofac Energy Developments UK Limited ...... England *100 *100 Jermyn Insurance Company Limited ...... Guernsey *100 *100 Petrofac Engineering India Private Limited ...... India 100 100 Petrofac Engineering Services India Private Limited ...... India 100 100 Petrofac Information Services Private Limited ...... India 100 100 PT. PCI Indonesia ...... Indonesia 80 80 Petrofac Iran (PJSC) ...... Iran — 100 Petrofac Pars (PJSC) ...... Iran — 100

CO2DeepStore Holdings Limited ...... Jersey 100 100 FPF1 Limited ...... Jersey 251 100 Monsoon Shipmanagement Limited ...... Jersey 100 100 Petrofac Energy Developments (Ohanet) Jersey Limited ..... Jersey 100 100 Petrofac Energy Developments International Limited ...... Jersey *100 *100 Petrofac Energy Developments West Africa Limited ...... Jersey 100 — Petrofac Facilities Management International Limited ...... Jersey *100 *100 Petrofac FPF004 Limited ...... Jersey 100 100 Petrofac FPSO Holding Limited ...... Jersey 100 100 Petrofac GSA Limited ...... Jersey 100 100

(1) Associate in 2012.

F-77 Notes to the consolidated financial statements continued For the year ended 31 December 2012

32 Principal subsidiaries and joint ventures continued

Proportion of nominal value of issued shares controlled by the Group Name of company Country of incorporation 2012 2011 Trading subsidiaries continued Petrofac International Ltd ...... Jersey *100 *100 Petrofac Offshore Management Limited ...... Jersey 100 100 Petrofac Platform Management Services Limited ...... Jersey 100 100 Petrofac Training International Limited ...... Jersey *100 *100 Petroleum Facilities E & C Limited ...... Jersey *100 *100 Petrokyrgyzstan Limited ...... Kyrgyzstan 100 100 Petrofac E&C Sdn Bhd ...... Malaysia 100 100 Petrofac Energy Developments Sdn Bhd ...... Malaysia 100 100 Petrofac Engineering Services (Malaysia) Sdn Bhd ...... Malaysia 100 — Petrofac FPF005 Limited ...... Malaysia 100 100 Petrofac Training Sdn Bhd ...... Malaysia 100 100 PFMAP Sdn Bhd ...... Malaysia 100 100 SPD Well Engineering Sdn Bhd ...... Malaysia 100 — H&L/SPD Americas S. de R.L...... Mexico 100 — Petrofac Mexico SA de CV ...... Mexico 100 100 Petrofac Mexico Servicios SA de CV ...... Mexico 100 100 Petro-SPM Integrated Services S.A. de C.V...... Mexico 50 — Petrofac Kazakhstan B.V...... Netherlands 100 100 Petrofac Mexico Holdings B.V...... Netherlands 100 — Petrofac Netherlands Cooperatief U.A...... Netherlands 100 100 Petrofac Netherlands Holdings B.V...... Netherlands 100 100 Petrofac Treasury B.V...... Netherlands 100 100 PTS B.V...... Netherlands 100 100 Petrofac Energy Services Nigeria Limited ...... Nigeria 100 — Petrofac International (Nigeria) Limited ...... Nigeria 100 100 KW Norge AS ...... Norway 100 100 Petrofac Norge AS ...... Norway 100 100 Petrofac E&C Oman LLC ...... Oman 100 100 Petrofac Solutions & Facilities Support S.R.L ...... Romania 100 100 PKT Technical Services Ltd ...... Russia **50 **50 PKT Training Services Ltd ...... Russia 100 100 Sakhalin Technical Training Centre ...... Russia 80 80 Petrofac Saudi Arabia Company Limited ...... Saudi Arabia 100 100 Atlantic Resourcing Limited ...... Scotland 100 100

CO2DeepStore Limited ...... Scotland 100 100 Petrofac Facilities Management Group Limited ...... Scotland 100 100 Petrofac Facilities Management Limited ...... Scotland 100 100 Petrofac Training Limited ...... Scotland 100 100 Scotvalve Services Limited ...... Scotland 100 100 SPD Limited ...... Scotland 100 100 Stephen Gillespie Consultants Limited ...... Scotland 100 100 i Perform Limited ...... Scotland 100 100 Petrofac Training Group Limited ...... Scotland 100 100 Petrofac Training Holdings Limited ...... Scotland 100 100 Plant Asset Management Limited ...... Scotland 100 100 Petrofac FPF003 Pte Limited ...... Singapore 100 100 Petrofac South East Asia Pte Ltd ...... Singapore 100 100 Petrofac Training Institute Pte Limited ...... Singapore 100 100 Petrofac International South Africa (Pty) Limited ...... South Africa 100 100 Petrofac E&C International Limited ...... United Arab Emirates 100 100

F-78 Notes to the consolidated financial statements continued For the year ended 31 December 2012

32 Principal subsidiaries and joint ventures continued

Proportion of nominal value of issued shares controlled by the Group Name of company Country of incorporation 2012 2011 Trading subsidiaries continued Petrofac FZE ...... United Arab Emirates 100 100 Petrofac International (UAE) LLC ...... United Arab Emirates 100 100 SPDLLC...... United Arab Emirates **49 **49 Petrofac Energy Developments (Ohanet) LLC ...... United States 100 100 Petrofac Inc...... United States *100 *100 Petrofac Training Inc...... United States 100 100 SPD Group Limited ...... British Virgin Islands 100 100

Joint Ventures MJVI Sdn Bhd ...... Brunei 50 50 Costain Petrofac Limited ...... England 50 50 PT. Petrofac IKPT International ...... Indonesia 51 51 Spie Capag – Petrofac International Limited ...... Jersey 50 50 TTE Petrofac Limited ...... Jersey 50 50 Kyrgyz Petroleum Company ...... Kyrgyz Republic — 50 Berantai Floating Production Limited ...... Malaysia 51 51 China Petroleum Petrofac Engineering Services Cooperatif U.A...... Netherlands 49 49 Professional Mechanical Repair Services Company ...... Saudi Arabia 50 — Petrofac Emirates LLC ...... United Arab Emirates 49 49

Dormant subsidiaries Monsoon Shipmanagement Limited ...... Cyprus — 100 Joint Venture International Limited ...... Scotland 100 100 Montrose Park Hotels Limited ...... Scotland 100 100 RGIT Ethos Health & Safety Limited ...... Scotland 100 100 Rubicon Response Limited ...... Scotland 100 100 Scota Limited ...... Scotland 100 100 Petrofac Training (Trinidad) Limited ...... Trinidad 100 100 Petrofac Services Inc ...... USA *100 *100 Petrofac ESOP Trustees Limited ...... Jersey *100 *100

* Directly held by Petrofac Limited ** Companies consolidated as subsidiaries on the basis of control.

The Company’s interest in joint venture operations are disclosed on page F-35.

F-79 Independent Auditors’ report to the members of Petrofac Limited

We have audited the Group financial statements of Petrofac Limited (the Company) and its subsidiaries (together ‘the Group’) for the year ended 31 December 2011 which comprise the consolidated income statement, the consolidated statement of comprehensive income, the consolidated statement of financial position, the consolidated statement of cash flows, the consolidated statement of changes in equity and the related notes 1 to 35. The financial reporting framework that has been applied in their preparation is applicable Jersey law and International Financial Reporting Standards.

This report is made solely to the Company’s members, as a body, in accordance with Article 113A of the Companies (Jersey) Law 1991 and our engagement letter dated 15 February 2011. Our audit work has been undertaken so that we might state to the Company’s members those matters we are required to state to them in an auditors’ report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company’s members as a body, for our audit work, for this report, or for the opinions we have formed.

Respective responsibilities of Directors and auditor As explained more fully in the statement of Directors’ responsibilities set out on page 106, the Directors are responsible for the preparation of the Group financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the Group financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors.

In addition the Company has also instructed us to: • report as to whether the information given in the corporate governance report with respect to internal control and risk management systems in relation to financial reporting processes and about share capital structures is consistent with the financial statements • review the directors’ statement in relation to going concern as set out on page 106, which for a premium listed UK incorporated company is specified for review by the Listing Rules of the Financial Services Authority

Scope of the audit of the financial statements An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting policies are appropriate to the Group’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant accounting estimates made by the Directors; and the overall presentation of the financial statements. In addition, we read all the financial and non-financial information in the annual report to identify material inconsistencies with the audited financial statements. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.

Opinion on financial statements In our opinion the Group financial statements: • give a true and fair view of the state of the Group’s affairs as at 31 December 2011 and of its profit for the year then ended • have been properly prepared in accordance with International Financial Reporting Standards • have been prepared in accordance with the requirements of the Companies (Jersey) Law 1991

Opinion on other matter In our opinion, the information given in the Corporate Governance Report set out on pages 68 to 90 with respect to internal control and risk management systems in relation to financial reporting processes and about share capital structures is consistent with the financial statements.

F-80 Matters on which we are required to report by exception We have nothing to report in respect of the following: • where the Companies (Jersey) Law 1991 requires us to report to you if, in our opinion: • proper accounting records have not been kept, or proper returns adequate for our audit have not been received from branches not visited by us; or • the financial statements are not in agreement with the accounting records and returns; or • we have not received all the information and explanations we require for our audit • under the Listing Rules we are required to review the part of the corporate governance report relating to the Company’s compliance with the nine provisions of the UK Corporate Governance Code specified for our review • where the Company instructed us to review the directors’ statement, set out on page 106, in relation to going concern

Other matter We have reported separately on the parent company financial statements of Petrofac Limited for the year ended 31 December 2011 and on the information in the Directors’ remuneration report that is described as having been audited.

Justine Belton for and on behalf of Ernst & Young LLP London

2 March 2012

Notes: 1 The maintenance and integrity of the Petrofac Limited website is the responsibility of the Directors; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the website. 2 Legislation in Jersey governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

F-81 Consolidated income statement For the year ended 31 December 2011

2011 2010 Notes US$’000 US$’000 Revenue ...... 4a 5,800,719 4,354,217 Cost of sales ...... 4b (4,840,943) (3,595,142) Gross profit ...... 959,776 759,075 Selling, general and administration expenses ...... 4c (283,392) (221,449) Gain on EnQuest demerger ...... 11 — 124,864 Other income ...... 4f 11,600 5,013 Other expenses ...... 4g (5,104) (4,053) Profit from operations before tax and finance income/(costs) ...... 682,880 663,450 Finance costs ...... 5 (6,599) (5,131) Finance income ...... 5 7,877 10,209 Share of losses of associates ...... 14 (3,593) (131) Profit before tax ...... 680,565 668,397 Income tax expense ...... 6 (140,984) (110,545) Profit for the year ...... 539,581 557,852 Attributable to: Petrofac Limited shareholders ...... 539,425 557,817 Non-controlling interests ...... 156 35 539,581 557,852 Earnings per share (US cents) ...... 7 – Basic (excluding gain on EnQuest demerger) ...... 159.01 127.76 – Diluted (excluding gain on EnQuest demerger) ...... 157.13 126.09 – Basic (including gain on EnQuest demerger) ...... 159.01 164.61 – Diluted (including gain on EnQuest demerger) ...... 157.13 162.46

The attached notes 1 to 35 form part of these consolidated financial statements.

F-82 Consolidated statement of comprehensive income For the year ended 31 December 2011

2011 2010 Notes US$’000 US$’000 Profit for the year ...... 539,581 557,852 Foreign currency translation ...... 26 (15,927) (908) Foreign currency translation recycled to income statement in the year on EnQuest demerger ...... 26 — 45,818 Net loss on maturity of cash flow hedges recycled in the period ...... 26 (3,675) (16,612) Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... 26 (13,590) (18,958) Net changes in the fair value of available-for-sale financial assets ...... 26 — 70 Disposal of available-for-sale financial assets ...... 26 (70) (74) Other comprehensive income ...... (33,262) 9,336 Total comprehensive income for the period ...... 506,319 567,188 Attributable to: Petrofac Limited shareholders ...... 506,163 567,153 Non-controlling interests ...... 156 35 506,319 567,188

The attached notes 1 to 35 form part of these consolidated financial statements.

F-83 Consolidated statement of financial position At 31 December 2011

2011 2010 Notes US$’000 US$’000 Assets Non-current assets Property, plant and equipment ...... 9 593,737 287,158 Goodwill ...... 12 106,681 105,832 Intangible assets ...... 13 121,821 85,837 Investments in associates ...... 14 164,405 16,349 Available-for-sale financial assets ...... 16 — 101,494 Other financial assets ...... 17 140,109 2,223 Deferred income tax assets ...... 6c 29,142 26,301 1,155,895 625,194 Current assets Non-current asset held for sale ...... 18 44,330 — Inventories ...... 19 10,529 7,202 Work in progress ...... 20 612,009 803,986 Trade and other receivables ...... 21 1,353,042 1,056,759 Due from related parties ...... 33 99,075 327 Other financial assets ...... 17 29,634 42,350 Income tax receivable ...... 15,364 2,525 Cash and short-term deposits ...... 22 1,572,338 1,063,005 3,736,321 2,976,154 Total assets ...... 4,892,216 3,601,348 Equity and liabilities Equity attributable to Petrofac Limited shareholders Share capital ...... 23 6,916 6,914 Share premium ...... 2,211 992 Capital redemption reserve ...... 10,881 10,881 Shares to be issued ...... — 994 Treasury shares ...... 24 (75,686) (65,317) Other reserves ...... 26 5,638 34,728 Retained earnings ...... 1,160,776 787,270 1,110,736 776,462 Non-controlling interests ...... 3,092 2,592 Total equity ...... 1,113,828 779,054 Non-current liabilities Interest-bearing loans and borrowings ...... 27 16,450 40,226 Provisions ...... 28 59,561 45,441 Other financial liabilities ...... 29 23,542 11,453 Deferred income tax liabilities ...... 6c 59,605 48,086 159,158 145,206 Current liabilities Trade and other payables ...... 30 1,744,182 1,021,436 Due to related parties ...... 33 23,166 11,710 Interest-bearing loans and borrowings ...... 27 60,711 47,435 Other financial liabilities ...... 29 31,677 37,054 Liabilities directly associated with non-current asset held for sale ...... 18 5,150 — Income tax payable ...... 96,122 105,559 Billings in excess of cost and estimated earnings ...... 20 389,404 178,429 Accrued contract expenses ...... 31 1,268,818 1,275,465 3,619,230 2,677,088 Total liabilities ...... 3,778,388 2,822,294 Total equity and liabilities ...... 4,892,216 3,601,348

The financial statements on pages F-60 to F-118 were approved by the Board of Directors on 2 March 2012 and signed on its behalf by Tim Weller – Chief Financial Officer.

The attached notes 1 to 35 form part of these consolidated financial statements.

F-84 Consolidated statement of cash flows For the year ended 31 December 2011

2011 2010 Notes US$’000 US$’000 Operating activities Profit before tax ...... 680,565 668,397 Gain on EnQuest demerger ...... — (124,864) 680,565 543,533 Non-cash adjustments to reconcile profit before tax to net cash flows: Depreciation, amortisation, impairment and write off ...... 4b,4c 80,088 95,903 Share-based payments ...... 4d 23,056 14,784 Difference between other long-term employment benefits paid and amounts recognised in the income statement ...... 9,450 6,074 Net finance income ...... 5 (1,278) (5,078) (Gain)/loss on disposal of property, plant and equipment ...... 4b,4f,4g (34) 315 Gain on fair value changes in Seven Energy warrants ...... 4f (5,647) — Gain on disposal of intangible assets ...... 4f — (2,338) Share of losses of associates ...... 14 3,593 131 Other non-cash items, net ...... 5,865 13,188 795,658 666,512 Working capital adjustments: Trade and other receivables ...... (300,567) (266,757) Work in progress ...... 191,977 (470,288) Due from related parties ...... (98,748) 17,933 Inventories ...... (3,327) (2,982) Other current financial assets ...... 17,142 (12,661) Trade and other payables ...... 735,124 167,707 Billings in excess of cost and estimated earnings ...... 210,975 (282,715) Accrued contract expenses ...... (6,647) 438,809 Due to related parties ...... 11,456 (45,616) Other current financial liabilities ...... 324 6,045 1,553,367 215,987 Long-term receivable from a customer ...... 17 (130,206) — Other non-current items, net ...... (196) (8,720) Cash generated from operations ...... 1,422,965 207,267 Interest paid ...... (3,156) (1,948) Income taxes paid, net ...... (156,848) (99,030) Net cash flows from operating activities ...... 1,262,961 106,289 Investing activities Purchase of property, plant and equipment ...... (420,360) (115,345) Acquisition of subsidiaries, net of cash acquired ...... 10 — (15,110) Payment of deferred consideration on acquisition ...... (15,969) — Purchase of other intangible assets ...... 13 (5,722) (153) Purchase of intangible oil & gas assets ...... 13 (39,728) (15,644) Cash outflow on EnQuest demerger (including transaction costs) ...... — (17,783) Investment in associates ...... 14 (50,282) (8,459) Purchase of available-for-sale financial assets ...... 16 — (101,494) Proceeds from disposal of property, plant and equipment ...... 886 3,219 Proceeds from disposal of available-for-sale financial assets ...... 243 539 Proceeds from sale of intangible assets ...... — 6,018 Interest received ...... 8,468 10,257 Net cash flows used in investing activities ...... (522,464) (253,955) Financing activities Repayment of interest-bearing loans and borrowings ...... (19,489) (32,458) Treasury shares purchased ...... 24 (49,062) (36,486) Equity dividends paid ...... (159,087) (132,244) Net cash flows used in financing activities ...... (227,638) (201,188) Net increase/(decrease) in cash and cash equivalents ...... 512,859 (348,854) Net foreign exchange difference ...... (11,550) (7,793) Cash and cash equivalents at 1 January ...... 1,034,097 1,390,744 Cash and cash equivalents at 31 December ...... 22 1,535,406 1,034,097

The attached notes 1 to 35 form part of these consolidated financial statements.

F-85 Consolidated statement of changes in equity For the year ended 31 December 2011

Attributable to shareholders of Petrofac Limited Issued Capital *Treasury Other Non- share Share redemption Shares to shares reserves Retained controlling Total capital premium reserve be issued US$’000 US$’000 earnings Total interests equity US$’000 US$’000 US$’000 US$’000 (note 24) (note 26) US$’000 US$’000 US$’000 US$’000 Balance at 1 January 2011 ...... 6,914 992 10,881 994 (65,317) 34,728 787,270 776,462 2,592 779,054 Net profit for the year ...... — — — — — — 539,425 539,425 156 539,581 Other comprehensive income ...... — — — — — (33,262) — (33,262) — (33,262) Total comprehensive income for the year ...... — — — — — (33,262) 539,425 506,163 156 506,319 Shares issued as payment of consideration on acquisition ...... 2 1,219 — (994) — — — 227 — 227 Share-based payments charge (note 25) ...... — — — — — 23,056 — 23,056 — 23,056 Shares vested during the year (note 24) ...... — — — — 38,693 (33,776) (4,917) — — — Transfer to reserve for share-based payments (note 25) ...... — — — — — 17,974 — 17,974 — 17,974 Treasury shares purchased (note 24)...... — — — — (49,062) — — (49,062) — (49,062) Income tax on share-based payments reserve ...... — — — — — (3,082) — (3,082) — (3,082) Dividends (note 8) ...... — — — — — — (161,002) (161,002) — (161,002) Movement in non-controlling interests ...... — — — — — — — — 344 344 Balance at 31 December 2011 ...... 6,916 2,211 10,881 — (75,686) 5,638 1,160,776 1,110,736 3,092 1,113,828

Attributable to shareholders of Petrofac Limited Issued Capital *Treasury Other Non- share Share redemption Shares to shares reserves Retained controlling Total capital premium reserve be issued US$’000 US$’000 earnings Total interests equity US$’000 US$’000 US$’000 US$’000 (note 24) (note 26) US$’000 US$’000 US$’000 US$’000 Balance at 1 January 2010 ...... 8,638 69,712 10,881 1,988 (56,285) 25,394 834,382 894,710 2,819 897,529 Net profit for the year ...... — — — — — — 557,817 557,817 35 557,852 Other comprehensive income ..... — — — — — 9,336 — 9,336 — 9,336 Total comprehensive income for the year ...... — — — — — 9,336 557,817 567,153 35 567,188 Shares issued as payment of consideration on acquisition .... 4 2,452 — (994) — — — 1,462 — 1,462 Share-based payments charge (note 25) ...... — — — — — 14,784 — 14,784 — 14,784 Shares vested during the year (note 24) ...... — — — — 27,454 (26,170) (1,284) — — — Transfer to reserve for share-based payments (note 25) ...... — — — — — 12,750 — 12,750 — 12,750 Treasury shares purchased (note 24) ...... — — — — (36,486) — — (36,486) — (36,486) Income tax on share-based payments reserve ...... — — — — — (1,366) — (1,366) — (1,366) EnQuest demerger share split and redemption ...... (1,728) — — — — — 1,728 — — — Distribution on EnQuest demerger ...... — (71,172) — — — — (473,325) (544,497) — (544,497) Dividends (note 8) ...... — — — — — — (132,048) (132,048) — (132,048) Movement in non-controlling interests ...... — — — — — — — — (262) (262) Balance at 31 December 2010 ..... 6,914 992 10,881 994 (65,317) 34,728 787,270 776,462 2,592 779,054

* Shares held by Petrofac Employee Benefit Trust and Petrofac Joint Venture Companies Employee Benefit Trust.

The attached notes 1 to 35 form part of these consolidated financial statements.

F-86 Notes to the consolidated financial statements For the year ended 31 December 2011

1 Corporate information The consolidated financial statements of Petrofac Limited (the Company) for the year ended 31 December 2011 were authorised for issue in accordance with a resolution of the Directors on 2 March 2012.

Petrofac Limited is a limited liability company registered and domiciled in Jersey under the Companies (Jersey) Law 1991 and is the holding company for the international group of Petrofac subsidiaries (together ‘the Group’). The Company’s 31 December 2011 financial statements are shown on pages 155 to 168. The Group’s principal activity is the provision of services to the oil & gas production and processing industry.

A full listing of all Group companies, and joint venture entities, is contained in note 35 to these consolidated financial statements.

New standards and interpretations The Group has adopted new and revised Standards and Interpretations issued by the International Accounting Standards Board (IASB) and the International Financial Reporting Interpretations Committee (IFRIC) of the IASB that are relevant to its operations and effective for accounting periods beginning on or after 1 January 2011. The principal effects of the adoption of these new and amended standards and improvements are discussed below: • IAS 24 Related Party Disclosures (amendment) effective 1 January 2011 • improvements to IFRS’s (May 2010): • IFRS 3 Business Combinations – measurement options available for non-controlling interest (NCI) effective 1 July 2010

F-87 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

• IFRS 7 Financial Instruments: Disclosures – collateral and qualitative disclosures • IAS 1 Presentation of Financial Statements – analysis of other comprehensive income

IAS 24 Related Party Disclosures (Amendment) The IASB has issued an amendment to IAS 24 that clarifies the identification of related party relationships, particularly in relation to significant influence or control. The new definitions emphasise a symmetrical view on related party relationships as well as clarifying in which circumstances persons and key management personnel affect related party relationships of an entity. While the adoption of the amendment did not have any current impact on the financial position, performance, or disclosure of the Group, as all required information is currently being appropriately captured and disclosed, it is relevant to the application of the Group’s accounting policy in identifying future potential related party relationships.

Improvements to IFRS The improvements did not have any impact on the accounting policies, financial position or performance of the Group.

IAS 1 Financial Statement Presentation – Presentation of Items of Other Comprehensive Income (OCI) The amendments to IAS 1 change the grouping of items presented in OCI. Items that could be reclassified (or ‘recycled’) to profit or loss at a future point in time (for example, upon de-recognition or settlement) would be presented separately from items that will never be reclassified. The amendment affects presentation only and has therefore no impact on the Group’s financial position or performance. The amendment becomes effective for annual periods beginning on or after 1 July 2012.

IAS 28 Investments in Associates and Joint Ventures (as revised in 2011) As a consequence of the new IFRS 11 and IFRS 12, IAS 28 has been renamed IAS 28 Investments in Associates and Joint Ventures, and describes the application of the equity method to investments in joint ventures in addition to associates. The Group is currently assessing the impact that this standard will have on its financial position and performance. The amendment becomes effective for annual periods beginning on or after 1 January 2013.

IFRS 7 Financial Instruments: Disclosures – Enhanced Derecognition Disclosure Requirements The amendment requires additional disclosure about financial assets that have been transferred but not derecognised to enable the user of the Group’s financial statements to understand the relationship with those assets that have not been de-recognised and their associated liabilities. In addition, the amendment requires disclosures about continuing involvement in de-recognised assets to enable the user to evaluate the nature of, and risks associated with, the entity’s continuing involvement in those de-recognised assets. The amendment affects

F-88 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued disclosure only and has no impact on the Group’s financial position or performance. The amendment becomes effective for annual periods beginning on or after 1 July 2011.

IFRS 9 Financial Instruments: Classification and Measurement IFRS 9 as issued reflects the first phase of the IASB’s work on the replacement of IAS 39 and applies to classification and measurement of financial assets and financial liabilities as defined in IAS 39. The standard is effective for annual periods beginning on or after 1 January 2015. In subsequent phases, the IASB will address hedge accounting and impairment of financial assets. The completion of this project is expected over the course of the first half of 2012. The adoption of the first phase of IFRS 9 will have an effect on the classification and measurement of the Group’s financial assets, but will potentially have no impact on classification and measurements of financial liabilities. The Group will quantify the effect in conjunction with the other phases, when issued, to present a comprehensive picture.

IFRS 10 establishes a single control model that applies to all entities including special purpose entities. The changes introduced by IFRS 10 will require management to exercise significant judgement to determine which entities are controlled, and therefore, are required to be consolidated by a parent, compared with the requirements that were in IAS 27. The Group is currently assessing the impact that this standard will have on its financial position and performance.

This standard becomes effective for annual periods beginning on or after 1 January 2013.

IFRS 11 Joint Arrangements IFRS 11 replaces IAS 31 Interests in Joint Ventures and SIC-13 Jointly-controlled Entities – Non-monetary Contributions by Venturers.

The application of this new standard will impact the financial position and performance of the Group but the quantification of this amount is still being determined. This standard becomes effective for annual periods beginning on or after 1 January 2013.

IFRS 12 Disclosure of Involvement with Other Entities IFRS 12 includes all of the disclosures that were previously in IAS 27 related to consolidated financial statements, as well as all of the disclosures that were previously included in IAS 31 and IAS 28. These disclosures relate to an entity’s interests in subsidiaries, joint arrangements, associates and structured entities. A number of new disclosures are also required. This standard becomes effective for annual periods beginning on or after 1 January 2013. The application of this standard affects disclosure only and will have no impact on the Group’s financial position or performance.

IFRS 13 Fair Value Measurement IFRS 13 establishes a single source of guidance under IFRS for all fair value measurements. IFRS 13 does not change when an entity is required to use fair value, but rather provides guidance on how to measure fair value under IFRS when fair value is required or permitted. The Group is currently assessing the impact that this standard will have on the financial position and performance of the Group. This standard becomes effective for annual periods beginning on or after 1 January 2013.

F-89 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

Estimation uncertainty The key assumptions concerning the future and other key sources of estimation uncertainty at the statement of financial position date, that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below: • project cost to complete estimates: at each statement of financial position date the Group is required to estimate costs to complete on fixed-price contracts. Estimating costs to complete on such contracts requires the Group to make estimates of future costs to be incurred, based on work to be performed beyond the statement of financial position date. This estimate will impact revenues, cost of sales, work-in-progress, billings in excess of costs and estimated earnings and accrued contract expenses • onerous contract provisions: the Group provides for future losses on long-term contracts where it is considered probable that the contract costs are likely to exceed revenues in future years. Estimating these future losses involves a number of assumptions about the achievement of contract performance targets and the likely levels of future cost escalation over time US$ nil (2010: US$2,523,000) • impairment of goodwill: the Group determines whether goodwill is impaired at least on an annual basis. This requires an estimation of the value in use of the cash-generating units to which the goodwill is allocated. Estimating the value in use requires the Group to make an estimate of the expected future cash flows from each cash-generating unit and also to determine a suitable discount rate in order to calculate the present value of those cash flows. The carrying amount of goodwill at 31 December 2011 was US$106,681,000 (2010: US$105,832,000) (note 12) • deferred tax assets: the Group recognises deferred tax assets on all applicable temporary differences where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the amount of deferred tax that can be recognised based on the magnitude and likelihood of future taxable profits. The carrying amount of deferred tax assets at 31 December 2011 was US$29,142,000 (2010: US$26,301,000) • income tax: the Company and its subsidiaries are subject to routine tax audits and also a process whereby tax computations are discussed and agreed with the appropriate authorities. Whilst the ultimate outcome of such tax audits and discussions cannot be determined with certainty, management estimates the level of provisions required for both current and deferred tax on the basis of professional advice and the nature of current discussions with the tax authority concerned • recoverable value of intangible oil & gas and other intangible assets: the Group determines at each statement of financial position date whether there is any evidence of indicators of impairment in the carrying value of its intangible oil & gas and other intangible assets. Where indicators exist, an impairment test is undertaken which requires management to estimate the recoverable value of its intangible assets for example by reference to quoted market values, similar arm’s length transactions involving these assets or value in use calculations • units of production depreciation: estimated proven plus probable reserves are used in determining the depreciation of oil & gas assets such that the depreciation charge is proportional to the depletion of the remaining reserves over their life of production. These calculations require the use of estimates including the amount of economically recoverable reserves and future oil & gas capital expenditure

F-90 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

Interests in joint ventures The Group has a number of contractual arrangements with other parties which represent joint ventures. These take the form of agreements to share control over other entities (jointly controlled entities) and commercial collaborations (jointly controlled operations). The Group’s interests in jointly controlled entities are accounted for by proportionate consolidation, which involves recognising the Group’s proportionate share of the joint venture’s assets, liabilities, income and expenses with similar items in the consolidated financial statements on a line-by-line basis. Where the Group collaborates with other entities in jointly controlled operations, the expenses the Group incurs and its share of the revenue earned is recognised in the consolidated income statement. Assets controlled by the Group and liabilities incurred by it are recognised in the statement of financial position. Where necessary, adjustments are made to the financial statements of the Group’s jointly controlled entities and operations to bring their accounting policies into line with those of the Group.

Investment in associates The Group’s investment in associates is accounted for using the equity method where the investment is initially carried at cost and adjusted for post acquisition changes in the Group’s share of net assets of the associate. Goodwill on the initial investment forms a part of the carrying amount of the investment and is not individually tested for impairment.

The financial statements of the associate are prepared using the same accounting policies and reporting periods as that of the Group.

On the disposal of a foreign entity, accumulated exchange differences are recognised in the consolidated income statement as a component of the gain or loss on disposal.

F-91 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

Oil & gas facilities ...... 10%–12.5% Plant and equipment ...... 4%–33% Buildings and leasehold improvements ..... 5%–33% (or lease term if shorter) Office furniture and equipment ...... 25%–100% Vehicles ...... 20%–33%

Tangible oil & gas assets are depreciated, on a field-by-field basis, using the unit-of-production method based on entitlement to proven and probable reserves, taking account of estimated future development expenditure relating to those reserves.

Each asset’s estimated useful life, residual value and method of depreciation are reviewed and adjusted if appropriate at each financial year end.

No depreciation is charged on land or assets under construction.

The carrying amount of an item of property, plant and equipment is derecognised on disposal or when no future economic benefits are expected from its use or disposal. The gain or loss arising from the derecognition of an item of property, plant and equipment is included in profit or loss when the item is derecognised. Gains are not classified as revenue.

Goodwill Goodwill acquired in a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually, or more frequently if events or changes in circumstances indicate that such carrying value may be impaired. All transaction costs associated with business combinations are charged to the consolidated income statement in the year of such combination.

F-92 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

Deferred consideration payable on a business combination When, as part of a business combination, the Group defers a proportion of the total purchase consideration payable for an acquisition, the amount provided for is the acquisition date fair value of the consideration. The unwinding of the discount element is recognised as a finance cost in the income statement. For business combinations prior to 1 January 2010, all changes in estimated deferred consideration payable on acquisition are adjusted against the carried goodwill. For business combinations after 1 January 2010, changes in estimated deferred consideration payable on acquisition are recognised in the consolidated income statement unless they are measurement period adjustments which are as a result of additional information obtained after the acquisition date about the facts and circumstances existing at the acquisition date, which are adjusted against carried goodwill.

Intangible assets – non oil & gas assets Intangible assets acquired in a business combination are initially measured at cost being their fair values at the date of acquisition and are recognised separately from goodwill where the asset is separable or arises from a contractual or other legal right and its fair value can be measured reliably. After initial recognition, intangible assets are carried at cost less accumulated amortisation and any accumulated impairment losses. Intangible assets with a finite life are amortised over their useful economic life using a straight-line method unless a better method reflecting the pattern in which the asset’s future economic benefits are expected to be consumed can be determined. The amortisation charge in respect of intangible assets is included in the selling, general and administration expenses line of the consolidated income statement. The expected useful lives of assets are reviewed on an annual basis. Any change in the useful life or pattern of consumption of the intangible asset is treated as a change in accounting estimate and is accounted for prospectively by changing the amortisation period or method. Intangible assets are tested for impairment whenever there is an indication that the asset may be impaired.

Oil & gas assets Capitalised costs The Group’s activities in relation to oil & gas assets are limited to assets in the evaluation, development and production phases.

Oil & gas evaluation and development expenditure is accounted for using the successful efforts method of accounting.

Evaluation expenditures Expenditure directly associated with evaluation (or appraisal) activities is capitalised as an intangible asset. Such costs include the costs of acquiring an interest, appraisal well drilling costs, payments to contractors and an appropriate share of directly attributable overheads incurred during the evaluation phase. For such appraisal activity, which may require drilling of further wells, costs continue to be carried as an asset whilst related hydrocarbons are considered capable of commercial development. Such costs are subject to technical, commercial and management review to confirm the continued intent to develop, or otherwise extract value. When this is no longer the case, the costs are written-off in the income statement. When such assets are declared part of a commercial development, related costs are transferred to tangible oil & gas assets. All intangible oil & gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the consolidated income statement.

F-93 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

Changes in unit-of-production factors Changes in factors which affect unit-of-production calculations are dealt with prospectively, not by immediate adjustment of prior years’ amounts.

The unwinding of the discount applied to future decommissioning provisions is included under finance costs in the income statement.

Available-for-sale financial assets Investments classified as available-for-sale are initially stated at fair value, including acquisition charges associated with the investment.

After initial recognition, available-for-sale financial assets are measured at their fair value using quoted market rates or in the absence of market data other fair value calculation methodologies. Gains and losses are recognised as a separate component of equity until the investment is sold or impaired, at which time the cumulative gain or loss previously reported in equity is included in the consolidated income statement.

F-94 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

De-recognition of financial assets and liabilities Financial assets A financial asset (or, where applicable a part of a financial asset) is de-recognised where: • the rights to receive cash flows from the asset have expired

F-95 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

• the Group retains the right to receive cash flows from the asset, but has assumed an obligation to pay them in full without material delay to a third-party under a ‘pass-through’ arrangement; or • the Group has transferred its rights to receive cash flows from the asset and either (a) has transferred substantially all the risks and rewards of the asset, or (b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset

Financial liabilities A financial liability is de-recognised when the obligation under the liability is discharged or cancelled or expires. If an existing financial liability is replaced by another from the same lender, on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a derecognition of the original liability and the recognition of a new liability such that the difference in the respective carrying amounts together with any costs or fees incurred are recognised in the consolidated income statement.

Pensions and other long-term employment benefits The Group has various defined contribution pension schemes in accordance with the local conditions and practices in the countries in which it operates. The amount charged to the consolidated income statement in respect of pension costs reflects the contributions payable in the year. Differences between contributions payable during the year and contributions actually paid are shown as either accrued liabilities or prepaid assets in the statement of financial position.

The Group’s other long-term employment benefits are provided in accordance with the labour laws of the countries in which the Group operates, further details of which are given in note 28.

The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the relevant employees become fully entitled to the award (the ‘vesting period’). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the Group’s best estimate of the number of equity instruments that will ultimately vest. The income statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

F-96 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

Company and its joint venture partner employees, which will be transferred to the members of the scheme on their respective vesting dates subject to satisfying the performance conditions of each scheme. The trusts have been consolidated in the Group financial statements in accordance with SIC 12 ‘Special Purpose Entities’. The cost of shares temporarily held by the trusts are reflected as treasury shares and deducted from equity.

Leases The determination of whether an arrangement is, or contains a lease is based on the substance of the arrangement at inception date of whether the fulfilment of the arrangement is dependent on the use of a specific asset or assets or the arrangement conveys the right to use the asset.

The Group has entered into various operating leases the payments for which are recognised as an expense in the consolidated income statement on a straight-line basis over the lease terms.

Revenues from cost-plus-fee contracts are recognised on the basis of costs incurred during the year plus the fee earned measured by the cost-to-cost method.

Revenues from reimbursable contracts are recognised in the period in which the services are provided based on the agreed contract schedule of rates.

Provision is made for all losses expected to arise on completion of contracts entered into at the statement of financial position date, whether or not work has commenced on these contracts.

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded and the amount of the incentive payments can be measured reliably. Claims and variation orders are only included in revenue when negotiations have reached an advanced stage such that it is probable the claim/variation orders will be accepted and can be measured reliably.

F-97 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded 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.

Integrated Energy Services Oil & gas revenues comprise the Group’s share of sales from the processing or sale of hydrocarbons on an entitlement basis, when the significant risks and rewards of ownership have been passed to the buyer.

Income taxes Income tax expense represents the sum of current income tax and deferred tax.

F-98 Notes to the consolidated financial statements continued For the year ended 31 December 2011

2 Summary of significant accounting policies continued

Derivative financial instruments and hedging The Group uses derivative financial instruments such as forward currency contracts, interest rate collars and swaps and oil price collars and forward contracts to hedge its risks associated with foreign currency, interest rate and oil price fluctuations. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.

Any gains or losses arising from changes in the fair value of derivatives that do not qualify for hedge accounting are taken to the consolidated income statement.

The fair value of forward currency contracts is calculated by reference to current forward exchange rates for contracts with similar maturity profiles. The fair value of interest rate cap, swap and oil price collar contracts is determined by reference to market values for similar instruments.

The treatment of gains and losses arising from revaluing derivatives designated as hedging instruments depends on the nature of the hedging relationship, as follows:

Cash flow hedges For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognised directly in the statement of changes in equity, while the ineffective portion is recognised in the income statement. Amounts taken to equity are transferred to the income statement when the hedged transaction affects the consolidated income statement.

F-99 Notes to the consolidated financial statements continued For the year ended 31 December 2011

3 Segment information As described on pages 12 to 13 during the year, the Group reorganised to deliver its services through four reporting segments; Onshore Engineering & Construction, Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services. As a result the segment information has been realigned to fit the new Group organisational structure which now comprises the following four reporting segments: • Onshore Engineering & Construction which provides engineering, procurement and construction project execution services to the onshore oil & gas industry • Offshore Projects & Operations which provides offshore engineering, operations and maintenance on and offshore • Engineering & Consulting Services which provides technical engineering, consultancy, conceptual design, front end engineering and design (FEED) and project management consultancy (PMC) across all sectors including renewables and carbon capture • Integrated Energy Services which co-invests with partners in oil & gas production, processing and transportation assets, provides production improvement services under value aligned commercial structures and oil & gas related technical competency training and consultancy services

Management separately monitors the trading results of its four reporting segments for the purpose of making an assessment of their performance and making decisions about how resources are allocated to them. Each segment’s performance is measured based on its profitability which is reflected in a manner consistent with the results shown below. However, certain shareholder services related overheads, Group financing and consolidation adjustments are managed at a corporate level and are not allocated to reporting segments.

F-100 Notes to the consolidated financial statements continued For the year ended 31 December 2011

3 Segment information continued

The following tables represent revenue and profit information relating to the Group’s reporting segments for the year ended 31 December 2011 and the comparative segmental information has been restated to reflect the revised Group organisational structure.

Year ended 31 December 2011

Onshore Offshore Engineering Integrated Consolidation Engineering & Projects & & Consulting Energy Corporate adjustments & Construction Operations Services Services & others eliminations Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Revenue External sales ...... 4,068,324 1,164,565 64,391 503,439 — — 5,800,719 Inter-segment sales ...... 77,894 86,787 143,775 15,417 — (323,873) — Total revenue ...... 4,146,218 1,251,352 208,166 518,856 — (323,873) 5,800,719 Segment results ...... 553,797 56,930 32,930 57,024 (420) (7,517) 692,744 Unallocated corporate costs . . . — — — — (9,864) — (9,864) Profit/(loss) before tax and finance income/(costs) ..... 553,797 56,930 32,930 57,024 (10,284) (7,517) 682,880 Share of loss of associate ..... — — — (3,593) — — (3,593) Finance costs ...... (1,450) (1,292) — (3,180) (2,921) 2,244 (6,599) Finance income ...... 8,375 212 58 357 1,807 (2,932) 7,877 Profit/(loss) before income tax...... 560,722 55,850 32,988 50,608 (11,398) (8,205) 680,565 Income tax (expense)/income ...... (97,734) (12,323) (2,170) (27,983) 1,415 (2,189) (140,984) Non-controlling interests ..... (156) — — — — — (156) Profit/(loss) for the year attributable to Petrofac Limited shareholders ..... 462,832 43,527 30,818 22,625 (9,983) (10,394) 539,425 Other segment information Capital expenditures: Property, plant and equipment ...... 54,028 58,572 7,599 311,948 6,059 (2,766) 435,440 Intangible oil & gas assets .... — — — 39,728 — — 39,728 Charges: Depreciation ...... 31,097 3,449 5,678 35,322 1,378 (145) 76,779 Amortisation ...... — 1,047 1,078 1,184 — — 3,309 Other long-term employment benefits ...... 12,013 352 — 396 100 — 12,861 Share-based payments ...... 11,863 2,521 774 3,674 4,224 — 23,056

F-101 Notes to the consolidated financial statements continued For the year ended 31 December 2011

3 Segment information continued

Year ended 31 December 2010 (as restated)

Onshore Offshore Engineering Integrated Consolidation Engineering & Projects & & Consulting Energy Corporate adjustments & Construction Operations Services Services & others eliminations Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Revenue External sales ...... 3,232,174 710,080 39,693 372,270 — — 4,354,217 Inter-segment sales ...... 21,732 11,821 133,739 11,964 — (179,256) — Total revenue ...... 3,253,906 721,901 173,432 384,234 — (179,256) 4,354,217 Segment results ...... 438,096 24,506 19,803 73,848 (900) (3,362) 551,991 Gain on EnQuest demerger . . . — — — 124,864 — — 124,864 Unallocated corporate costs . . — — — — (13,405) — (13,405) Profit/(loss) before tax and finance income/(costs) .... 438,096 24,506 19,803 198,712 (14,305) (3,362) 663,450 Share of loss of associate .... — — — (131) — — (131) Finance costs ...... — (968) (12) (3,805) (3,659) 3,313 (5,131) Finance income ...... 9,741 209 142 731 2,699 (3,313) 10,209 Profit/(loss) before income tax...... 447,837 23,747 19,933 195,507 (15,265) (3,362) 668,397 Income tax (expense)/income ...... (74,848) (6,519) 1,215 (32,668) 2,275 — (110,545) Non-controlling interests .... (35) — — — — — (35) Profit/(loss) for the year attributable to Petrofac Limited shareholders .... 372,954 17,228 21,148 162,839 (12,990) (3,362) 557,817 Other segment information Capital expenditures: Property, plant and equipment ...... 59,522 2,785 3,597 46,938 4,575 (1,178) 116,239 Intangible oil & gas assets . . . — — — 15,644 — — 15,644 Charges: Depreciation ...... 33,710 2,238 4,719 52,933 367 (575) 93,392 Amortisation ...... — 597 1,044 870 — — 2,511 Other long-term employment benefits ...... 10,435 613 41 1,594 87 — 12,770 Share-based payments ...... 7,693 1,167 718 2,299 2,907 — 14,784

F-102 Notes to the consolidated financial statements continued For the year ended 31 December 2011

3 Segment information continued

Year ended 31 December 2011

United Arab United Other Emirates Kingdom Turkmenistan Malaysia Algeria Kuwait Qatar countries Consolidated US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Revenues from external customers ...... 1,290,673 938,606 768,283 653,395 749,204 379,178 256,657 764,723 5,800,719

United United Arab Other Kingdom Emirates Tunisia Algeria Malaysia Thailand countries Consolidated US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Non-current assets: Property, plant and equipment . . . 71,276 104,466 41,824 26,889 255,958 47,854 45,470 593,737 Intangible oil & gas assets ...... 1,130 — — — 102,345 — — 103,475 Other intangible assets ...... 12,510 — — — — — 5,836 18,346 Goodwill ...... 91,268 14,914 — — — — 499 106,681

Year ended 31 December 2010

United Arab United Other Algeria Emirates Kingdom Kuwait Oman Syria Saudi Arabia countries Consolidated US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Revenues from external customers ...... 1,037,966 798,328 753,842 360,624 350,313 277,196 235,936 540,012 4,354,217

United United Arab Other Kingdom Emirates Tunisia Algeria Malaysia Indonesia countries Consolidated US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Non-current assets: Property, plant and equipment ...... 54,326 94,292 52,031 30,737 14,836 1,555 39,381 287,158 Intangible oil & gas assets .... — — — — 69,532 — — 69,532 Other intangible assets ...... 9,365 — — — — 6,940 — 16,305 Goodwill ...... 90,093 15,240 — — — — 499 105,832

Revenues disclosed in the above tables are based on where the project is located. Revenue from two customers amounted to US$1,651,994,000 (2010: US$1,422,410,000) in the Onshore Engineering & Construction segment.

4 Revenues and expenses a. Revenue

2011 2010 US$’000 US$’000 Rendering of services ...... 5,650,892 4,202,371 Sale of crude oil & gas ...... 143,122 146,075 Sale of processed hydrocarbons ...... 6,705 5,771 5,800,719 4,354,217

F-103 Notes to the consolidated financial statements continued For the year ended 31 December 2011

4 Revenues and expenses continued

Included in revenues from rendering of services are Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services revenues of a ‘pass-through’ nature with zero or low margins amounting to US$229,422,000 (2010: US$227,974,000). The revenues are included as external revenues of the Group since the risks and rewards associated with its recognition are assumed by the Group. b. Cost of sales Included in cost of sales for the year ended 31 December 2011 is US$62,000 loss (2010: US$154,000 gain) on disposal of property, plant and equipment used to undertake various engineering and construction contracts. In addition, depreciation charged on property, plant and equipment of US$62,180,000 during 2011 (2010: US$85,186,000) is included in cost of sales (note 9).

Also included in cost of sales are forward points and ineffective portions on derivatives designated as cash flow hedges and losses on undesignated derivatives of US$5,881,000 (2010: US$3,409,000 loss). These amounts are an economic hedge of foreign exchange risk but do not meet the criteria within IAS 39 and are most appropriately recorded in cost of sales. c. Selling, general and administration expenses

2011 2010 US$’000 US$’000 Staff costs ...... 186,462 126,475 Depreciation (note 9) ...... 14,599 8,206 Amortisation (note 13) ...... 3,309 2,511 Other operating expenses ...... 79,022 84,257 283,392 221,449

Other operating expenses consist mainly of office, travel, legal and professional and contracting staff costs. d. Staff costs

2011 2010 US$’000 US$’000 Total staff costs: Wages and salaries ...... 1,044,361 828,439 Social security costs ...... 37,936 31,809 Defined contribution pension costs ...... 20,576 12,621 Other long-term employee benefit costs (note 28) ...... 14,313 12,770 Expense of share-based payments (note 25) ...... 23,056 14,784 1,140,242 900,423

Of the US$1,140,242,000 (2010: US$900,423,000) of staff costs shown above, US$953,780,000 (2010: US$773,948,000) are included in cost of sales, with the remainder in selling, general and administration expenses.

The average number of persons employed by the Group during the year was 13,212 (2010: 12,807).

F-104 Notes to the consolidated financial statements continued For the year ended 31 December 2011

4 Revenues and expenses continued e. Auditors’ remuneration The Group paid the following amounts to its auditors in respect of the audit of the financial statements and for other services provided to the Group:

2011 2010 US$’000 US$’000 Group audit fee ...... 1,124 958 Audit of accounts of subsidiaries ...... 1,007 798 Audit related assurance services ...... 301 239 Taxation compliance services ...... 200 75 Other taxation services ...... 435 445 All other non-audit services ...... 88 119 3,155 2,634 f. Other income

2011 2010 US$’000 US$’000 Foreign exchange gains ...... 2,564 720 Gain on sale of property, plant and equipment ...... 140 8 Gain on sale of available-for-sale financial assets ...... 70 — Gain on fair value changes in Seven Energy warrants (note 14) ...... 5,647 — Gain on sale of intangible assets ...... — 2,338 Other income ...... 3,179 1,947 11,600 5,013 g. Other expenses

2011 2010 US$’000 US$’000 Foreign exchange losses ...... 3,716 3,452 Loss on sale of property, plant and equipment ...... 44 477 Other expenses ...... 1,344 124 5,104 4,053

5 Finance (costs)/income

2011 2010 US$’000 US$’000 Interest payable: Long-term borrowings ...... (2,561) (2,908) Other interest, including short-term loans and overdrafts ...... (1,734) (581) Unwinding of discount on provisions ...... (2,304) (1,642) Total finance cost ...... (6,599) (5,131) Interest receivable: Bank interest receivable ...... 7,594 9,945 Other interest receivable ...... 283 264 Total finance income ...... 7,877 10,209

F-105 Notes to the consolidated financial statements continued For the year ended 31 December 2011

6 Income tax a. Tax on ordinary activities The major components of income tax expense are as follows:

2011 2010 US$’000 US$’000 Current income tax Current income tax charge ...... 138,205 115,199 Adjustments in respect of current income tax of previous years ...... 782 (2,843) Deferred income tax Relating to origination and reversal of temporary differences ...... 8,832 907 Adjustments in respect of deferred income tax of previous years ...... (6,835) (2,718) Income tax expense reported in the income statement ...... 140,984 110,545 b. Reconciliation of total tax charge A reconciliation between the income tax expense and the product of accounting profit multiplied by the Company’s domestic tax rate is as follows:

2011 2010 US$’000 US$’000 Accounting profit before tax ...... 680,565 668,397 At Jersey’s domestic income tax rate of 0% (2010: 0%) ...... — — Expected tax charge in higher rate jurisdictions ...... 141,347 116,199 Expenditure not allowable for income tax purposes ...... 2,741 1,073 Adjustments in respect of previous years ...... (6,053) (5,561) Tax effect of utilisation of tax losses not previously recognised ...... (607) (568) Unrecognised tax losses ...... 1,388 1,634 Other permanent differences ...... 1,338 (2,157) Effect of change in tax rates ...... 830 (75) At the effective income tax rate of 20.7% (2010: 16.5%) ...... 140,984 110,545

The Group’s effective tax rate for the year ended 31 December 2011 is 20.7% (2010: 16.5% including EnQuest demerger; 20.3% excluding EnQuest demerger). No chargeable gain arose for UK corporate tax purposes on the 2010 demerger of Petrofac’s UKCS business to EnQuest Plc. Excluding the gain on demerger, there has been no significant change to the Group’s effective tax rate. Any variance results from changes in jurisdictions in which profits are expected to be earned. From 1 April 2012 the UK corporation tax rate will be 25% and the change in UK rate was substantially enacted as at the balance sheet date. This change will impact the reversal of the temporary difference from this date onwards, reducing the Group’s UK deferred tax assets and liabilities for the period ended 31 December 2011.

F-106 Notes to the consolidated financial statements continued For the year ended 31 December 2011

6 Income tax continued c. Deferred income tax Deferred income tax relates to the following:

Consolidated statement of Consolidated financial position income statement 2011 2010 2011 2010 US$’000 US$’000 US$’000 US$’000 Deferred income tax liabilities Fair value adjustment on acquisitions ...... 2,889 1,412 1,477 (597) Accelerated depreciation ...... 42,884 36,581 6,303 14,630 Profit recognition ...... 13,655 7,896 5,760 (4,768) Other temporary differences ...... 177 2,197 (2,020) 432 Gross deferred income tax liabilities ...... 59,605 48,086 Deferred income tax assets Losses available for offset ...... 1,846 2,258 412 (14,135) Decelerated depreciation for tax purposes ...... 1,967 2,403 436 327 Share scheme ...... 9,950 15,721 (911) (230) Profit recognition ...... 11,310 4,160 (7,150) — Other temporary differences ...... 4,069 1,759 (2,310) 2,530 Gross deferred income tax assets ...... 29,142 26,301 Deferred income tax charge/(credit) ...... 1,997 (1,811)

Certain items of other temporary differences in 2010 have been reclassified to be consistent with current year presentation. d. Unrecognised tax losses and tax credits Deferred income tax assets are recognised for tax loss carry-forwards and tax credits to the extent that the realisation of the related tax benefit through future taxable profits is probable. The Group did not recognise deferred income tax assets of US$26,626,000 (2010: US$18,366,000).

2011 2010 US$’000 US$’000 Expiration dates for tax losses No earlier than 2022 ...... 8,917 9,466 No expiration date ...... 4,032 6,384 12,949 15,850 Tax credits (no expiration date) ...... 13,677 2,516 26,626 18,366

Diluted earnings per share amounts are calculated by dividing the net profit attributable to ordinary shareholders, after adjusting for any dilutive effect, by the weighted average number of ordinary shares outstanding during the year, adjusted for the effects of ordinary shares granted under the employee share award schemes which are held in trust.

F-107 Notes to the consolidated financial statements continued For the year ended 31 December 2011

7 Earnings per share continued

The following reflects the income and share data used in calculating basic and diluted earnings per share:

2011 2010 US$’000 US$’000 Net profit attributable to ordinary shareholders for basic and diluted earnings per share excluding gain on EnQuest demerger ...... 539,425 432,953 Net profit attributable to ordinary shareholders for basic and diluted earnings per share including gain on EnQuest demerger ...... 539,425 557,817

2011 2010 Number Number ’000 ’000 Weighted average number of ordinary shares for basic earnings per share ...... 339,239 338,867 Effect of diluted potential ordinary shares granted under share-based payment schemes .... 4,069 4,493 Adjusted weighted average number of ordinary shares for diluted earnings per share ...... 343,308 343,360

8 Dividends paid and proposed

2011 2010 US$’000 US$’000 Declared and paid during the year Equity dividends on ordinary shares: Final dividend for 2009: 25.10 cents per share ...... — 85,291 Interim dividend 2010: 13.80 cents per share ...... — 46,757 Final dividend for 2010: 30.00 cents per share ...... 101,788 — Interim dividend 2011: 17.40 cents per share ...... 59,214 — 161,002 132,048

2011 2010 US$’000 US$’000 Proposed for approval at AGM (not recognised as a liability as at 31 December) Equity dividends on ordinary shares Final dividend for 2011: 37.20 cents per share (2010: 30.00 cents per share) ...... 128,670 103,715

F-108 Notes to the consolidated financial statements continued For the year ended 31 December 2011

9 Property, plant and equipment

Land, Office Oil & Oil & buildings and furniture Assets gas gas leasehold Plant and and under assets facilities improvements equipment Vehicles equipment construction Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Cost At 1 January 2010 ...... 555,901 157,983 115,542 22,980 10,896 87,089 6,679 957,070 Additions ...... 32,252 7,602 44,114 1,445 4,755 19,238 6,833 116,239 Acquisition of subsidiaries ...... — — — 2,081 46 43 — 2,170 Disposals ...... (470,447) — (1,847) (2,344) (854) (17,268) — (492,760) Transfers ...... — — 881 4 — (885) — — Exchange difference ...... — — (462) (712) (158) (809) (132) (2,273) At 1 January 2011 ...... 117,706 165,585 158,228 23,454 14,685 87,408 13,380 580,446 Additions ...... 2,774 306,704 63,619 5,388 2,815 29,926 24,214 435,440 Disposals ...... — — (1,718) (2,269) (631) (10,311) — (14,929) Transfers ...... — (44,330) (20) — — 13,172 (13,152) (44,330) Exchange difference ...... (2,638) (1,721) (2,504) (245) — (1,103) (277) (8,488) At 31 December 2011 ...... 117,842 426,238 217,605 26,328 16,869 119,092 24,165 948,139 Depreciation At 1 January 2010 ...... (77,171) (102,280) (22,030) (16,618) (5,786) (55,189) — (279,074) Charge for the year ...... (32,204) (15,993) (23,981) (2,734) (3,462) (15,018) — (93,392) Disposals ...... 59,592 — 1,400 538 769 16,072 — 78,371 Transfers ...... — — (83) — — 83 — — Exchange difference ...... — — 71 327 28 381 — 807 At 1 January 2011 ...... (49,783) (118,273) (44,623) (18,487) (8,451) (53,671) — (293,288) Charge for the year ...... (13,390) (18,697) (19,978) (1,321) (3,502) (19,891) — (76,779) Disposals ...... — — 1,567 2,234 412 9,864 — 14,077 Transfers ...... — — 12 — — (12) — — Exchange difference ...... 913 28 316 14 5 312 — 1,588 At 31 December 2011 ...... (62,260) (136,942) (62,706) (17,560) (11,536) (63,398) — (354,402) Net carrying amount: At 31 December 2011 ...... 55,582 289,296 154,899 8,768 5,333 55,694 24,165 593,737 At 31 December 2010 ...... 67,923 47,312 113,605 4,967 6,234 33,737 13,380 287,158

No interest has been capitalised within oil & gas facilities during the year (2010: nil) and the accumulated capitalised interest, net of depreciation at 31 December 2011, was nil (2010: US$432,000).

Additions to oil & gas facilities in 2011 mainly comprise of the purchase and upgrade of the FPF1, FPSO Berantai, FPF3, FPF4 and FPF5 for a combined cost of US$305,394,000. Transfers from oil & gas facilities include the transfer of the FPF1 to non-current asset held for sale as part of the pending Ithaca transaction (note 18).

Included in oil & gas assets are US$3,262,000 (2010: US$2,196,000) of capitalised decommissioning costs net of depreciation provided on the PM304 asset in Malaysia and the Chergui asset in Tunisia.

Of the total charge for depreciation in the income statement, US$62,180,000 (2010: US$85,186,000) is included in cost of sales and US$14,599,000 (2010: US$8,206,000) in selling, general and administration expenses.

F-109 Notes to the consolidated financial statements continued For the year ended 31 December 2011

9 Property, plant and equipment continued

Assets under construction comprise expenditures incurred in relation to a new office building in the United Arab Emirates and the Group ERP project.

Included in land, buildings and leasehold improvements is property, plant and equipment under finance lease agreements, for which book values are as follows:

Net book value US$’000 Gross book value ...... 35,809 Depreciation ...... (994) At 31 December 2011 ...... 34,815 At 31 December 2010 ...... —

10 Business combinations Scotvalve Services Limited On 14 January 2010, the Group acquired a 100% interest in the share capital of Scotvalve Services Limited (Scotvalve), a UK based company, involved in the servicing and repair of oilfield pressure control equipment. The consideration for the acquisition was sterling 4,630,000 (equivalent US$7,512,000) comprising of sterling 2,801,000 (equivalent US$4,545,000) as an initial cash payment, sterling 150,000 (equivalent US$243,000) to be settled in cash during 2010 and the balance being the discounted value of deferred consideration amounting to sterling 1,679,000 (equivalent US$2,724,000) payable based on the estimated future profitability of Scotvalve. The range of deferred consideration payable was from zero to a maximum of sterling 2,000,000 (equivalent US$3,122,000) over a three year period.

The fair value of net assets acquired was US$4,967,000 which included fair value of intangible assets recognised on acquisition of US$1,107,000.

These intangible assets recognised on acquisition comprise equipment manufacturer warranty repair licenses which are being amortised over their remaining economic useful lives of five years on a straight-line basis.

The residual goodwill of US$2,437,000 (2010: US$2,449,000) comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the Group.

During the year a charge of US$54,000 (2010: US$59,000) for the unwinding of interest on deferred consideration payable has been reflected in the consolidated income statement.

The deferred consideration payable was re-assessed at year end in light of latest financial projections for the business and the current carried amount was reduced by sterling 459,000, equivalent US$735,000 (2010: sterling 135,000, equivalent US$208,000) with a corresponding increase in other income within the consolidated income statement.

Stephen Gillespie Consultants Limited On 1 April 2010, the Group acquired a 100% interest in the share capital of Stephen Gillespie Consultants Limited (SGC), a UK based provider of software consultancy to flow metering control system manufacturers for a consideration of sterling 4,523,000 (equivalent US$6,853,000) comprising of sterling 3,178,000 (equivalent US$4,815,000) paid upfront in cash and the balance being the discounted value of deferred consideration amounting to sterling 1,345,000 (equivalent US$2,038,000) payable based on the estimated future revenue of the company. The range of deferred consideration payable is from sterling 600,000 (equivalent US$937,000) to a maximum of sterling 1,200,000 (equivalent US$1,873,000) based on future revenue of SGC over a two year period.

The fair value of net assets acquired was US$3,382,000 which included fair value of intangible assets recognised on acquisition of US$2,065,000.

F-110 Notes to the consolidated financial statements continued For the year ended 31 December 2011

10 Business combinations continued

These intangible assets recognised on acquisition comprise of software related to metering technology which is being amortised over its remaining economic useful lives of five years on a straight-line basis.

The residual goodwill of US$3,562,000 (2010: US$3,578,000) comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the Group.

During the year a charge of US$ nil (2010: US$25,000) for the unwinding of interest has been reflected in the consolidated income statement.

The deferred consideration payable was re-assessed at year end in light of latest financial projections for the business and the current carried amount was reduced by sterling 214,000, equivalent US$343,000 (2010: sterling 188,000, equivalent US$293,000) with a corresponding increase in other income within the consolidated income statement.

CO2DeepStore Limited On 27 April 2010, the Group acquired a 100% interest in the share capital of CO2DeepStore Limited

(CO2DeepStore), a United Kingdom based company focused on the CO2 geological storage sector of the carbon capture and storage market for a cash consideration of sterling 220,000 (equivalent US$340,000).

The fair value of net assets acquired was US$340,000.

Under the terms of the acquisition agreement, costs of up to sterling 200,000 (equivalent US$312,000) will be payable to the former owners of CO2DeepStore three years from the date of completion based on the estimated future profitability of the company and will be recognised as an expense in the income statement over this period. The charge for the current year is sterling 67,000, equivalent US$107,000 (2010: sterling 44,000, equivalent US$68,000).

TNEI Services Limited On 14 June 2010, the Group acquired a 100% interest in the share capital of TNEI Services Limited (TNEI) through the acquisition of its holding company New Energy Industries Limited for a cash consideration of sterling 6,123,000 (equivalent US$8,913,000). TNEI provides services in the areas of power transmission and distribution, planning and environmental consent and energy management.

The fair value of net assets acquired was US$2,587,000.

The residual goodwill of US$7,695,000 (2010: US$7,728,000) comprises the fair value of expected future synergies and business opportunities arising from the integration of the business into the Group.

Under the terms of the acquisition agreement, sterling 1,538,000 (equivalent US$2,370,000) will be payable 50% in Petrofac shares and 50% in cash to the former owners of TNEI who remain as employees of the Petrofac Group in three equal tranches over three years from the date of completion which will be recognised as an expense in the income statement on a straight-line basis over the three years. The charge for the current year is sterling 513,000, equivalent US$821,000 (2010: sterling 278,000, equivalent US$428,000).

11 Gain on EnQuest demerger On 5 April 2010, the Group’s interests in the Don area oil assets were demerged via a transfer of three of its subsidiaries, Petrofac Energy Developments Limited (PEDL), Petrofac Energy Developments Oceania Limited (PEDOL) and PEDL Limited (PEDLL) to EnQuest PLC for a deemed consideration for accounting purposes of US$553,300,000 which was settled by the issue of EnQuest PLC shares directly to Petrofac Limited shareholders. A gain of US$124,864,000 was made on the demerger transaction.

F-111 Notes to the consolidated financial statements continued For the year ended 31 December 2011

12 Goodwill A summary of the movements in goodwill is presented below:

2011 2010 US$’000 US$’000 At 1 January ...... 105,832 97,922 Acquisitions during the year (note 10) ...... — 13,223 Reassessment of deferred consideration payable ...... 820 (1,313) Write off on EnQuest demerger ...... — (1,146) Exchange difference ...... 29 (2,854) At 31 December ...... 106,681 105,832

Reassessment of deferred consideration payable comprises of the increase in deferred consideration payable on SPD Group Limited of US$820,000 (2010: US$3,141,000) and Caltec Limited of US$ nil (2010: US$4,285,000 decrease).

These represent the lowest level within the Group at which the goodwill is monitored for internal management purposes. The goodwill previously monitored separately for Production Solutions, Training Services and Energy Developments is now monitored on a combined basis following the Group reorganisation.

Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services cash- generating units The recoverable amounts for the Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services cash-generating units have been determined based on value in use calculations, using discounted pre-tax cash flow projections. Management has adopted a ten-year projection period to assess each unit’s value in use as it is confident based on past experience of the accuracy of long-term cash flow forecasts that these projections are reliable. The cash flow projections are based on financial budgets approved by senior management covering a five-year period, extrapolated for a further five years at a growth rate of 5% for Offshore Projects & Operations and Engineering & Consulting Services cash-generating units. For the Integrated Energy Services business the cash flows are based on field models over a ten-year horizon for Production Enhancement Contracts and Risk Service Contracts and on financial budgets approved by senior management covering a five- year period, extrapolated for a further five years at a growth rate of 2.5% for other operations as these include acquired businesses where there is less track record of achieving financial projections.

Carrying amount of goodwill allocated to each group of cash-generating units

2011 2010 US$’000 US$’000 Offshore Projects & Operations unit ...... 27,904 27,992 Engineering & Consulting Services unit ...... 7,695 7,728 Integrated Energy Services unit ...... 71,082 70,112 106,681 105,832

F-112 Notes to the consolidated financial statements continued For the year ended 31 December 2011

12 Goodwill continued

Key assumptions used in value in use calculations for the Offshore Projects & Operations, Engineering & Consulting Services and Integrated Energy Services units: Market share: the assumption relating to market share for the Offshore Projects & Operations unit is based on the unit re-securing those existing customer contracts in the UK which are due to expire during the projection period; for the Training business which is within Integrated Energy Services, the key assumptions relate to management’s assessment of maintaining the unit’s market share in the UK and developing further the business in international markets.

Reserve volumes and production profiles: management has used its internally developed economic models of reserves and production as inputs in to the value in use for the Production Enhancement, Risk Service and Production Sharing Contracts. Management has used an oil price of US$85 per barrel to determine reserve volumes on Production Sharing Contracts.

Growth rate: estimates are based on management’s assessment of market share having regard to macro- economic factors and the growth rates experienced in the recent past by each unit. A growth rate of 5% per annum has been applied for the Offshore Projects & Operations and Engineering & Consulting Services cash- generating units for the remaining five years of the ten-year projection period and 2.5% per annum for the Integrated Energy Services cash-generating unit since it includes newly acquired businesses where there is less historic track record of achieving financial projections.

Discount rate: management has used a pre-tax discount rate of 13.8% per annum. In 2010 a discount rate of 14.6% was used for the Offshore Projects & Operations, Engineering & Consulting Services, Production Solutions and Training Services cash-generating units and a rate of 13.4% for the Energy Developments cash generating unit. The discount rate is derived from the estimated weighted average cost of capital of the Group and has been calculated using an estimated risk free rate of return adjusted for the Group’s estimated equity market risk premium and the Group’s cost of debt.

Sensitivity to changes in assumptions With regard to the assessment of value in use of the cash-generating units, management believes that no reasonably possible change in any of the above key assumptions would cause the carrying value of the relevant unit to exceed its recoverable amount, after giving due consideration to the macro-economic outlook for the oil & gas industry and the commercial arrangements with customers underpinning the cash flow forecasts for each of the units.

F-113 Notes to the consolidated financial statements continued For the year ended 31 December 2011

13 Intangible assets

2011 2010 US$’000 US$’000 Intangible oil & gas assets Cost: At 1 January ...... 69,532 53,888 Additions ...... 39,728 15,644 Transfer to costs ...... (5,785) — Net book value of intangible oil & gas assets at 31 December ...... 103,475 69,532 Other intangible assets Cost: At 1 January ...... 24,538 25,476 Additions on acquisition (note 10) ...... — 3,172 Additions ...... 5,722 153 Disposal ...... — (4,220) Exchange difference ...... (504) (43) At 31 December ...... 29,756 24,538 Accumulated amortisation: At 1 January ...... (8,233) (6,257) Amortisation ...... (3,309) (2,511) Disposal ...... — 540 Exchange difference ...... 132 (5) At 31 December ...... (11,410) (8,233) Net book value of other intangible assets at 31 December ...... 18,346 16,305 Total intangible assets ...... 121,821 85,837

Intangible oil & gas assets Oil & gas asset (part of the Integrated Energy Services segment) additions above comprise of US$38,688,000 (2010: US$15,644,000) of capitalised expenditure on the Group’s assets in Malaysia.

There were investing cash outflows relating to capitalised intangible oil & gas assets of US$39,728,000 (2010: US$15,644,000) in the current period arising from pre-development activities.

US$5,785,000 relates to a long-term receivable from a customer on the Berantai RSC contract being their share of development expenditure, which was transferred to costs.

Other intangible assets Other intangible asset additions above largely consist of US$4,003,000 of gas storage project development costs and US$1,634,000 of competency training software that formed part of the acquisition during the year of Skills XP.

Other intangible assets comprising project development expenditure customer contracts, proprietary software, LNG intellectual property and patent technology are being amortised over their estimated economic useful life on a straight-line basis and the related amortisation charges included in selling, general and administrative expenses (note 4c).

14 Investments in associates

2011 2010 US$’000 US$’000 Investment in Gateway Storage Company Limited ...... 14,835 15,601 Associates acquired through acquisition of Scotvalve (note 10) ...... 745 748 Investment in Seven Energy International Limited transferred from available-for-sale financial assets (note 16) ...... 148,825 — 164,405 16,349

F-114 Notes to the consolidated financial statements continued For the year ended 31 December 2011

14 Investments in associates continued

Gateway Storage Company Limited On 6 December 2010, the Group acquired a 20% equity interest in Gateway Storage Company Limited (Gateway), an unlisted entity, to progress and develop the Gateway Gas Storage project in the East Irish Sea. The initial cost of the investment was sterling 5,000,000 (equivalent US$7,795,000) together with transaction costs of US$664,000 and contracted value of free services to be provided by the Group of sterling 500,000 (equivalent US$780,000). Additional contingent payments may become payable under the terms of the investment, subject to key project development milestones being achieved, including the outcome of further successful equity sales. Deferred consideration of sterling 4,160,000 (equivalent US$6,556,000) has been estimated as payable using a discounted storage project cash flow model assuming certain project scenarios to which estimated probabilities were assigned by management. The deferred consideration in no event will exceed an additional amount of sterling 28,000,000 (equivalent US$43,705,000).

The share of the associate’s statement of financial position is as follows:

2011 2010 US$’000 US$’000 Non-current assets ...... 154 123 Current assets ...... 1,612 3,050 Current liabilities ...... (40) (795) Equity ...... 1,726 2,378 Transaction costs incurred ...... 720 664 Fair value of free services to be provided ...... 780 780 Deferred consideration payable ...... 6,556 6,556 Exchange ...... (364) (194) Residual goodwill ...... 5,417 5,417 Carrying value of investment ...... 14,835 15,601 Share of associates revenues and net loss: Revenue ...... — — Net loss ...... (885) (131)

Seven Energy International Limited On 25 November 2010, the Company invested US$100,000,000 for 15% (12.6% on a fully diluted basis) of the share capital of Seven Energy International Limited (Seven Energy), a leading Nigerian gas development and production company incurring US$1,251,000 of transaction costs. This investment which was previously held under available-for-sale financial assets was transferred to investment in associates, pursuant to an investment on 10 June 2011 of US$50,000,000 for an additional 5% of the share capital of Seven Energy which resulted in the Group being in a position to exercise significant influence over Seven Energy. The Company also has the option to subscribe for 148,571 of additional warrants in Seven Energy at a cost of a further US$52,000,000, subject to the performance of certain service provision conditions and milestones in relation to project execution. These warrants have been fair valued at 31 December 2011 as derivative financial instruments under IAS 39, using Black Scholes Model, amounting to US$17,616,000 (2010:US$11,969,000). US$5,647,000 has been recognised as other income in the current period income statement as a result of the revaluation of these derivatives at 31 December 2011 (note 4f). At 31 December 2011, there was a corresponding entry for the fair value in trade and other payables representing the deferred revenue relating to the performance conditions. This deferred revenue is released as revenue in the income statement in line with the percentage of performance conditions satisfied at each reporting date. At 31 December 2011, 80% of the performance conditions have been completed (2010: nil) resulting in current year revenue recognised of US$9,576,000.

F-115 Notes to the consolidated financial statements continued For the year ended 31 December 2011

14 Investments in associates continued

The share of the associate’s statement of financial position is as follows: 2011 US$’000 Non-current assets ...... 92,563 Current assets ...... 21,965 Non-current liabilities ...... (47,597) Current liabilities ...... (10,970) Equity ...... 55,961 Transaction costs incurred ...... 1,533 Residual goodwill ...... 91,331 Carrying value of investment ...... 148,825 Share of associates revenues and net loss: Revenue ...... 24,289 Net loss ...... (2,708)

15 Interest in joint ventures In the normal course of business, the Group establishes jointly controlled entities for the execution of certain of its operations and contracts. A list of these joint ventures is disclosed in note 35. The Group’s share of assets, liabilities, revenues and expenses relating to jointly controlled entities is as follows: 2011 2010 US$’000 US$’000 Revenue ...... 452,672 194,848 Cost of sales ...... (375,538) (171,233) Gross profit ...... 77,134 23,615 Selling, general and administration expenses ...... (49,786) (14,286) Other (expense)/income, net ...... — (6,553) Finance income, net ...... 440 643 Profit before income tax ...... 27,788 3,419 Income tax ...... (792) (263) Net profit ...... 26,996 3,156 Current assets ...... 172,117 94,935 Non-current assets ...... 182,746 27,634 Total assets ...... 354,863 122,569 Current liabilities ...... 272,080 120,892 Non-current liabilities ...... 57,256 1,658 Total liabilities ...... 329,336 122,550 Net assets ...... 25,527 19

16 Available-for-sale financial assets 2011 2010 US$’000 US$’000 Seven Energy International Limited ...... — 101,251 Shares — listed ...... — 243 — 101,494

The investment in Seven Energy International Limited was transferred to investment in associates (note 14), pursuant to an additional investment made during the year, which took the Group’s holding in the share capital of Seven Energy to over 20% (2010: 15%).

F-116 Notes to the consolidated financial statements continued For the year ended 31 December 2011

17 Other financial assets

2011 2010 US$’000 US$’000 Other financial assets – non-current Fair value of derivative instruments (note 34) ...... — 12 Long-term receivable from a customer ...... 130,206 — Restricted cash ...... 307 266 Other ...... 9,596 1,945 140,109 2,223 Other financial assets – current Seven Energy warrants (note 14) ...... 17,616 11,969 Fair value of derivative instruments (note 34) ...... 8,553 9,183 Interest receivable ...... 140 731 Restricted cash ...... 2,506 19,196 Other ...... 819 1,271 29,634 42,350

Long-term receivable from a customer relates to an amount due on the Berantai RSC.

Restricted cash comprises deposits with financial institutions securing various guarantees and performance bonds associated with the Group’s trading activities (note 32). This cash will be released on the maturity of these guarantees and performance bonds. Included in other non-current financial assets are transition costs relating to the Santuario, Magallanes and Ticleni Production Enhancement Contracts which are recoverable over the lives of these contracts.

18 Asset held for sale

2011 2010 US$’000 US$’000 Non-current asset held for sale (note 9) ...... 44,330 — Liabilities directly associated with non-current asset held for sale ...... 5,150 —

Non-current asset held for sale comprises FPF1 Ltd pending the completion of the Ithaca transaction. This entry is reported under the Integrated Energy Services segment.

19 Inventories

2011 2010 US$’000 US$’000 Crude oil ...... 3,942 2,119 Processed hydrocarbons ...... 84 90 Stores and spares ...... 5,650 4,083 Raw materials ...... 853 910 10,529 7,202

Included in the consolidated income statement are costs of inventories expensed of US$31,706,000 (2010: US$28,840,000).

F-117 Notes to the consolidated financial statements continued For the year ended 31 December 2011

20 Work in progress and billings in excess of cost and estimated earnings

2011 2010 US$’000 US$’000 Cost and estimated earnings ...... 12,066,357 7,812,897 Less: billings ...... (11,454,348) (7,008,911) Work in progress ...... 612,009 803,986 Billings ...... 2,856,375 2,144,252 Less: cost and estimated earnings ...... (2,466,971) (1,965,823) Billings in excess of cost and estimated earnings ...... 389,404 178,429 Total cost and estimated earnings ...... 14,533,328 9,778,720 Total billings ...... 14,310,723 9,153,163

21 Trade and other receivables

2011 2010 US$’000 US$’000 Trade receivables ...... 869,124 785,383 Retentions receivable ...... 71,375 26,297 Advances ...... 215,470 179,101 Prepayments and deposits ...... 30,802 34,059 Receivables from joint venture partners ...... 121,477 — Other receivables ...... 44,794 31,919 1,353,042 1,056,759

2011 2010 Specific General Specific General impairment impairment Total impairment impairment Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 At 1 January ...... 2,790 2,935 5,725 4,875 1,754 6,629 Charge for the year ...... 524 (412) 112 2,189 1,796 3,985 Amounts written off ...... (294) (1,854) (2,148) (2,197) (67) (2,264) Unused amounts reversed ...... (235) (120) (355) (1,738) (893) (2,631) Transfers ...... ———(326) 326 — Exchange difference ...... (9) (39) (48) (13) 19 6 At 31 December ...... 2,776 510 3,286 2,790 2,935 5,725

F-118 Notes to the consolidated financial statements continued For the year ended 31 December 2011

21 Trade and other receivables continued

At 31 December, the analysis of trade receivables is as follows:

Neither past Number of days past due due nor 31-60 61-90 91-120 121-360 > 360 impaired < 30 days days days days days days Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Unimpaired ...... 570,445 156,310 108,780 13,857 3,615 13,233 616 866,856 Impaired ...... — — — — 2,445 2,207 902 5,554 570,445 156,310 108,780 13,857 6,060 15,440 1,518 872,410 Less: impairment provision ...... — — — — (441) (1,932) (913) (3,286) Net trade receivables 2011 ...... 570,445 156,310 108,780 13,857 5,619 13,508 605 869,124 Unimpaired ...... 599,661 125,821 34,562 10,897 7,324 834 164 779,263 Impaired ...... — 3,230 1,085 157 1,633 4,023 1,717 11,845 599,661 129,051 35,647 11,054 8,957 4,857 1,881 791,108 Less: impairment provision ...... — (1,211) (391) (244) (774) (2,295) (810) (5,725) Net trade receivables 2010 . . 599,661 127,840 35,256 10,810 8,183 2,562 1,071 785,383

Advances represent payments made to certain of the Group’s subcontractors for projects in progress, on which the related work had not been performed at the statement of financial position date. The increase in advances during 2011 relates to new contract awards in the Onshore Engineering & Construction business partly offset by the unwinding of advances on more mature contracts.

Receivables from joint venture partners are amounts recoverable from venture partners on the Berantai floating production platform and PM304.

All trade and other receivables are expected to be settled in cash.

Certain trade and other receivables will be settled in cash using currencies other than the reporting currency of the Group, and will be largely paid in sterling and euros.

22 Cash and short-term deposits

2011 2010 US$’000 US$’000 Cash at bank and in hand ...... 490,446 244,018 Short-term deposits ...... 1,081,892 818,987 Total cash and bank balances ...... 1,572,338 1,063,005

F-119 Notes to the consolidated financial statements continued For the year ended 31 December 2011

22 Cash and short-term deposits continued

For the purposes of the consolidated cash flow statement, cash and cash equivalents comprise the following:

2011 2010 US$’000 US$’000 Cash at bank and in hand ...... 490,446 244,018 Short-term deposits ...... 1,081,892 818,987 Bank overdrafts (note 27) ...... (36,932) (28,908) 1,535,406 1,034,097

23 Share capital The share capital of the Company as at 31 December was as follows:

2011 2010 US$’000 US$’000 Authorised 750,000,000 ordinary shares of US$0.020 each (2010: 750,000,000 ordinary shares of US$0.020 each) ...... 15,000 15,000 Issued and fully paid 345,821,729 ordinary shares of US$0.020 each (2010: 345,715,053 ordinary shares of US$0.020 each) ...... 6,916 6,914

The movement in the number of issued and fully paid ordinary shares is as follows:

Number Ordinary shares: **Ordinary shares of US$0.025 each at 1 January 2010 ...... 345,532,388 Issued during the year as further deferred consideration payable for the acquisition of a subsidiary ...... 182,665 Ordinary shares of US$0.020 each at 1 January 2011 ...... 345,715,053 Issued during the year as further deferred consideration payable for the acquisition of subsidiaries ...... 106,676 Ordinary shares of US$0.020 each at 31 December 2011 ...... 345,821,729

The share capital comprises only one class of ordinary shares. The ordinary shares carry a voting right and the right to a dividend.

Share premium: The balance on the share premium account represents the amount received in excess of the nominal value of the ordinary shares.

Capital redemption reserve: The balance on the capital redemption reserve represents the aggregated nominal value of the ordinary shares repurchased and cancelled.

**In order to effect the demerger of the PEDL sub group to EnQuest, the existing issued ordinary share capital of Petrofac Limited was subdivided and converted into new ordinary Petrofac shares with a nominal value of US$0.02 each and Petrofac B shares of US$0.005 each and subsequent to this share split the B shares were purchased and cancelled in exchange for an allotment and issue of EnQuest ordinary shares directly to holders of Petrofac B shares.

F-120 Notes to the consolidated financial statements continued For the year ended 31 December 2011

24 Treasury shares For the purpose of making awards under its employee share schemes, the Company acquires its own shares which are held by the Petrofac Employee Benefit Trust and the Petrofac Joint Venture Companies Employee Benefit Trust. All these shares have been classified in the statement of financial position as treasury shares within equity.

The movements in total treasury shares are shown below:

2011 2010 Number US$’000 Number US$’000 At 1 January ...... 6,757,339 65,317 7,210,965 56,285 Acquired during the year ...... 2,074,138 49,062 2,122,960 36,486 Vested during the year ...... (3,095,460) (38,693) (2,576,586) (27,454) At 31 December ...... 5,736,017 75,686 6,757,339 65,317

Shares vested during the year include dividend shares and 8% uplift adjustment made in respect of the EnQuest demerger of 393,344 (2010: 120,504).

25 Share-based payment plans Performance Share Plan (PSP) Under the Performance Share Plan of the Company, share awards are granted to Executive Directors and a restricted number of other senior executives of the Group. The shares cliff vest at the end of three years subject to continued employment and the achievement of certain pre-defined non-market and market-based performance conditions. The non-market-based condition governing the vesting of 50% of the total award, is subject to achieving between 10% and 20% earning per share (EPS) growth targets over a three-year period. The fair values of the equity-settled award relating to the EPS part of the scheme are estimated based on the quoted closing market price per Company share at the date of grant with an assumed vesting rate per annum built into the calculation (subsequently trued up at year end based on the actual leaver rate during the period from award date to year end) over the three-year vesting period of the plan. The fair value and assumed vesting rates of the EPS part of the scheme are shown below:

Fair value Assumed per share vesting rate 2011 awards ...... 1,426p 94.3% 2010 awards ...... 1,103p 93.8% 2009 awards ...... 545p 93.1% 2008 awards ...... 522p 92.3%

The remaining 50% market performance based part of these awards is dependent on the total shareholder return (TSR) of the Group compared to an index composed of selected relevant companies. The fair value of the shares vesting under this portion of the award is determined by an independent valuer using a Monte Carlo simulation model taking into account the terms and conditions of the plan rules and using the following assumptions at the date of grant:

2011 awards 2010 awards 2009 awards 2008 awards Expected share price volatility (based on median of comparator Group’s three-year volatilities) ...... 51.0% 50.0% 49.0% 32.0% Share price correlation with comparator Group ...... 43.0% 39.0% 36.0% 22.0% Risk-free interest rate ...... 1.7% 1.50% 2.10% 3.79% Expected life of share award ...... 3 years 3 years 3 years 3 years Fair value of TSR portion ...... 788p 743p 456p 287p

F-121 Notes to the consolidated financial statements continued For the year ended 31 December 2011

25 Share-based payment plans continued

The following shows the movement in the number of shares held under the PSP scheme outstanding but not exercisable:

2011 2010 Number Number Outstanding at 1 January ...... 1,350,189 1,432,680 Granted during the year ...... 482,379 390,278 Vested during the year ...... (421,309) (407,316) Forfeited during the year ...... (53,213) (65,453) Outstanding at 31 December ...... 1,358,046 1,350,189

The number of outstanding shares excludes the 8% uplift adjustment made in respect of the EnQuest demerger of 47,335 shares (2010: 82,594 shares) and any rolled up declared dividends of 68,073 shares (2010: 64,264 shares). The 8% uplift adjustment compensated the existing share plan holders for the loss in market value of Petrofac shares on flotation of EnQuest and employees have no legal right to receive dividend shares until the shares ultimately vest.

The number of awards still outstanding but not exercisable at 31 December 2011 is made up of 454,969 in respect of 2011 awards (2010: nil), 368,005 in respect of 2010 awards (2010: 390,278), 535,072 in respect of 2009 awards (2010: 538,602), and nil in respect of 2008 awards (2010: 421,309).

The charge recognised in the current year amounted to US$5,999,000 (2010: US$3,208,000).

Deferred Bonus Share Plan (DBSP) Executive Directors and selected employees were originally eligible to participate in this scheme although the Remuneration Committee decided in 2007 that Executive Directors should no longer continue to participate. Participants are required, or in some cases invited, to receive a proportion of any bonus in ordinary shares of the Company (‘Invested Awards’). Following such an award, the Company will generally grant the participant an additional award of a number of shares bearing a specified ratio to the number of his or her invested shares (‘Matching Shares’).

A change in the rules of the DBSP scheme was approved by shareholders at the annual general meeting of the Company on 11 May 2007 such that the 2007 share awards and for any awards made thereafter, the Invested and Matching Shares would, unless the Remuneration Committee of the Board of Directors determined otherwise, vest 33.33% on the first anniversary of the date of grant, a further 33.33% on the second anniversary of the date of grant and the final 33.34% of the award on the third anniversary of the date of grant.

At the year end the values of the bonuses settled by shares cannot be determined until all employees have confirmed the voluntary portion of their bonus they wish to be settled by shares rather than cash and until the Remuneration Committee has approved the mandatory portion of the employee bonuses to be settled in shares. Once the voluntary and mandatory portions of the bonus to be settled in shares are determined, the final bonus liability to be settled in shares is transferred to the reserve for share-based payments. The costs relating to the Matching Shares are recognised over the corresponding vesting period and the fair values of the equity-settled Matching Shares granted to employees are based on the quoted closing market price at the date of grant adjusted for the trued up percentage vesting rate of the plan. The details of the fair values and assumed vesting rates of the DBSP scheme are below:

Fair value Assumed per share vesting rate 2011 awards ...... 1,426p 97.0% 2010 awards ...... 1,185p 90.8% 2009 awards ...... 545p 91.8% 2008 awards ...... 522p 90.9%

F-122 Notes to the consolidated financial statements continued For the year ended 31 December 2011

25 Share-based payment plans continued

The following shows the movement in the number of shares held under the DBSP scheme outstanding but not exercisable:

2011 2010 Number* Number* Outstanding at 1 January ...... 4,082,311 4,694,191 Granted during the year ...... 1,538,252 1,397,094 Vested during the year ...... (1,681,130) (1,792,895) Forfeited during the year ...... (129,687) (216,079) Outstanding at 31 December ...... 3,809,746 4,082,311

*Includes Invested and Matching Shares.

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger of 188,177 shares (2010: 327,058 shares) and rolled up declared dividends of 158,691 shares (2010: 184,599 shares).

The number of awards still outstanding but not exercisable at 31 December 2011 is made up of 1,491,298 in respect of 2011 awards (2010: nil), 984,496 in respect of 2010 awards (2010: 1,313,894), 1,333,952 in respect of 2009 awards (2010: 1,948,340), and nil in respect of 2008 awards (2010: 820,077).

The charge recognised in the 2011 income statement in relation to matching share awards amounted to US$12,920,000 (2010: US$9,195,000).

Share Incentive Plan (SIP) All UK employees, including UK Executive Directors, are eligible to participate in the scheme. Employees may invest up to sterling 1,500 per tax year of gross salary (or, if lower, 10% of salary) to purchase ordinary shares in the Company. There is no holding period for these shares.

Restricted Share Plan (RSP) Under the Restricted Share Plan scheme, selected employees are granted shares in the Company over a discretionary vesting period which may or may not be, at the direction of the Remuneration Committee of the Board of Directors, subject to the satisfaction of performance conditions. At present there are no performance conditions applying to this scheme nor is there currently any intention to introduce them in the future. The fair values of the awards granted under the plan at various grant dates during the year are based on the quoted market price at the date of grant adjusted for an assumed vesting rate over the relevant vesting period. For details of the fair values and assumed vesting rate of the RSP scheme, see below:

Weighted average Assumed fair value vesting per share rate 2011 awards ...... 1,463p 99.3% 2010 awards ...... 990p 92.3% 2009 awards ...... 430p 70.0% 2008 awards ...... 478p 97.6%

F-123 Notes to the consolidated financial statements continued For the year ended 31 December 2011

25 Share-based payment plans continued

The following shows the movement in the number of shares held under the RSP scheme outstanding but not exercisable:

2011 2010 Number Number Outstanding at 1 January ...... 1,003,712 1,082,461 Granted during the year ...... 204,402 203,384 Vested during the year ...... (664,512) (176,360) Forfeited during the year ...... (8,822) (105,773) Outstanding at 31 December ...... 534,780 1,003,712

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger of 27,982 shares (2010: 78,156 shares) and rolled up declared dividends of 27,090 shares (2010: 48,474 shares).

The number of awards still outstanding but not exercisable at 31 December 2011 is made up of 204,402 in respect of 2011 awards (2010: nil), 186,758 in respect of 2010 awards (2010: 195,580), 36,658 in respect of 2009 awards (2010: 36,658), 1,030 in respect of 2008 awards (2010: 665,542), and 105,932 in respect of 2007 awards (2010: 105,932).

The charge recognised in the 2011 income statement in relation to RSP awards amounted to US$4,137,000 (2010: US$2,381,000).

The Group has recognised a total charge of US$23,056,000 (2010: US$14,784,000) in the consolidated income statement during the year relating to the above employee share-based schemes (see note 4d) which has been transferred to the reserve for share-based payments along with US$17,974,000 of the bonus liability accrued for the year ended 31 December 2010 which has been settled in shares granted during the year (2010: US$12,750,000).

For further details on the above employee share-based payment schemes refer to pages 97 to 101 of the Directors’ remuneration report.

F-124 Notes to the consolidated financial statements continued For the year ended 31 December 2011

26 Other reserves

Net unrealised gains/(losses) Net on available- unrealised for-sale- (losses)/ Foreign Reserve for financial gains on currency share-based assets derivatives translation payments Total US$’000 US$’000 US$’000 US$’000 US$’000 Balance at 1 January 2010 ...... 74 32,773 (64,328) 56,875 25,394 Foreign currency translation ...... — — (908) — (908) Foreign currency translation recycled to consolidated income statement in the year on EnQuest demerger (note 11) ...... — — 45,818 — 45,818 Net gains on maturity of cash flow hedges recycled in the year ...... — (16,612) — — (16,612) Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... — (18,958) — — (18,958) Net changes in fair value of available-for-sale financial assets ...... 70 — — — 70 Disposal of available-for-sale financial assets ...... (74) — — — (74) Share-based payments charge (note 25) ...... — — — 14,784 14,784 Transfer during the year (note 25) ...... — — — 12,750 12,750 Shares vested during the year (note 25) ...... — — — (26,170) (26,170) Deferred tax on share-based payments reserve ...... — — — (1,366) (1,366) Balance at 1 January 2011 ...... 70 (2,797) (19,418) 56,873 34,728 Foreign currency translation ...... — — (15,927) — (15,927) Net gains on maturity of cash flow hedges recycled in the year ...... — (3,675) — — (3,675) Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... — (13,590) — — (13,590) Disposal of available-for-sale financial assets ...... (70) — — — (70) Share-based payments charge (note 25) ...... — — — 23,056 23,056 Transfer during the year (note 25) ...... — — — 17,974 17,974 Shares vested during the year (note 25) ...... — — — (33,776) (33,776) Deferred tax on share-based payments reserve ...... — — — (3,082) (3,082) Balance at 31 December 2011 ...... — (20,062) (35,345) 61,045 5,638

Nature and purpose of other reserves Net unrealised gains/(losses) on available-for-sale financial assets This reserve records fair value changes on available-for-sale financial assets held by the Group net of deferred tax effects. Realised gains and losses on the sale of available-for-sale financial assets are recognised as other income or expenses in the consolidated income statement.

Net unrealised gains/(losses) on derivatives The portion of gains or losses on cash flow hedging instruments that are determined to be effective hedges are included within this reserve net of related deferred tax effects. When the hedged transaction occurs or is no longer forecast to occur, the gain or loss is transferred out of equity to the consolidated income statement. Realised net gains amounting to US$3,979,000 (2010: US$16,764,000) relating to foreign currency forward contracts and financial assets designated as cash flow hedges have been recognised in cost of sales and a realised net loss of US$304,000 (2010: US$152,000) was deducted from revenues in respect of oil derivatives.

The forward currency points element and ineffective portion of derivative financial instruments relating to forward currency contracts and gains on un-designated derivatives amounting to a net loss of US$5,881,000 (2010: US$3,409,000 loss) have been recognised in the cost of sales.

F-125 Notes to the consolidated financial statements continued For the year ended 31 December 2011

26 Other reserves continued

The transfer during the year reflects the transfer from accrued expenses within trade and other payables of the bonus liability relating to the year ended 2011 of US$17,974,000 (2010 bonus of US$12,750,000) which has been voluntarily elected or mandatorily obliged to be settled in shares during the year (note 25).

27 Interest-bearing loans and borrowings The Group had the following interest-bearing loans and borrowings outstanding:

31 December 2011 31 December 2010 Effective 2011 2010 Actual interest rate % Actual interest rate % interest rate % Maturity US$’000 US$’000 Current Bank overdrafts (i) UK LIBOR + 1.50% UK LIBOR + 1.50%, UK LIBOR on demand 36,932 28,908 US LIBOR + 1.50% US LIBOR + 1.50% + 1.50%, US LIBOR + 1.50% Other loans: Current portion of term loan (ii) US/UK LIBOR US/UK LIBOR 3.16% to 3.96% 17,119 14,241 + 0.875% + 0.875% (2010: 3.26% to 4.14%) Current portion of term loan (iii) US/UK LIBOR US/UK LIBOR 1.67% to 3.55% 6,660 4,286 + 0.875% + 0.875% (2010: 2.01% to 3.91%) 60,711 47,435 Non-current Term loan (ii) US/UK LIBOR US/UK LIBOR 3.16% to 3.96% 2012-2013 12,433 30,576 + 0.875% + 0.875% (2010: 3.26% to 4.14%) Term loan (iii) US/UK LIBOR US/UK LIBOR 1.67% to 3.55% 2012-2013 7,133 13,809 + 0.875% + 0.875% (2010: 2.01% to 3.91%) 19,566 44,385 Less: Debt acquisition costs net of accumulated amortisation and effective rate adjustments (3,116) (4,159) 16,450 40,226

Details of the Group’s interest-bearing loans and borrowings are as follows:

(i) Bank overdrafts Bank overdrafts are drawn down in US dollars and sterling denominations to meet the Group’s working capital requirements. These are repayable on demand.

(ii) Term loan This term loan at 31 December 2011 comprised drawings of US$14,857,000 (2010: US$23,057,000) denominated in US dollars and US$14,695,000 (2010: US$21,760,000) denominated in sterling. Both elements of the loan are repayable over a period of three years ending 30 September 2013.

F-126 Notes to the consolidated financial statements continued For the year ended 31 December 2011

27 Interest-bearing loans and borrowings continued

(iii) Term loan This term loan at 31 December 2011 comprised drawings of US$10,075,000 (2010: US$13,203,000) denominated in US dollars and US$3,718,000 (2010: US$4,892,000) denominated in sterling. Both elements of the loan are repayable over a period of three years ending 30 September 2013.

The Group’s credit facilities and debt agreements contain covenants relating to interest and net borrowings cover. None of the Company’s subsidiaries are subject to any material restrictions on their ability to transfer funds in the form of cash dividends, loans or advances to the Company.

28 Provisions

Other long- term employment Provision benefits for Other provision decommissioning provisions Total US$’000 US$’000 US$’000 US$’000 At 1 January 2011 ...... 40,204 3,676 1,561 45,441 Additions during the year ...... 12,861 2,649 1,237 16,747 Unused amounts reversed ...... — (835) — (835) Paid in the year ...... (3,411) — — (3,411) Unwinding of discount ...... 1,452 167 — 1,619 At 31 December 2011 ...... 51,106 5,657 2,798 59,561

Other long-term employment benefits provision Labour laws in the United Arab Emirates require employers to provide for other long-term employment benefits. These benefits are payable to employees on being transferred to another jurisdiction or on cessation of employment based on their final salary and number of years service. All amounts are unfunded. The long-term employment benefits provision is based on an internally produced end of service benefits valuation model with the key underlying assumptions being as follows:

Senior Other employees employees Average number of years of future service ...... 5 3 Average annual % salary increases ...... 6% 4% Discount factor ...... 4% 4%

Senior employees are those earning a base of salary of over US$96,000 per annum.

Discount factor used is the local Dubai five-year Sukuk rate.

Provision for decommissioning The decommissioning provision primarily relates to the Group’s obligation for the removal of facilities and restoration of the site at the PM304 field in Malaysia and at Chergui in Tunisia. The liability is discounted at the rate of 4.16% on PM304 (2010: 3.80%) and 5.25% on Chergui (2010: 5.25%). The unwinding of the discount is classified as finance cost (note 5). The Group estimates that the cash outflows against these provisions will arise in 2026 on PM304 and in 2018 on Chergui.

Other provisions This represents amounts set aside to cover claims against the Group which will be settled via the captive insurance company Jermyn Insurance Company Limited.

F-127 Notes to the consolidated financial statements continued For the year ended 31 December 2011

29 Other financial liabilities

2011 2010 US$’000 US$’000 Other financial liabilities – non-current Deferred consideration payable ...... 12,889 11,279 Finance lease creditors (note 32) ...... 10,644 — Fair value of derivative instruments (note 34) ...... — 174 Other ...... 9 — 23,542 11,453 Other financial liabilities – current Deferred consideration payable ...... 3,379 24,595 Interest payable ...... 107 9 Fair value of derivative instruments (note 34) ...... 22,466 12,197 Finance lease creditors (note 32) ...... 5,392 — Other ...... 333 253 31,677 37,054

Included in deferred consideration payable above is an amount payable of US$6,466,000 (2010: US$6,556,000) relating to the Group’s investment in an associate (note 14).

30 Trade and other payables

2011 2010 US$’000 US$’000 Trade payables ...... 476,851 278,383 Advances received from customers ...... 769,637 412,044 Accrued expenses ...... 414,725 251,512 Other taxes payable ...... 24,571 12,755 Other payables ...... 58,398 66,742 1,744,182 1,021,436

Advances from customers represent payments received for contracts on which the related work had not been performed at the statement of financial position date.

Included in other payables are retentions held against subcontractors of US$29,200,000 (2010: US$6,170,000). Also included in other payables above is US$2,393,000 (2010: U$11,969,000) deferred revenue relating to the provision of services required to earn the right to subscribe for the additional Seven Energy warrants (note 14).

Certain trade and other payables will be settled in currencies other than the reporting currency of the Group, mainly in sterling, euros and Kuwaiti dinars.

31 Accrued contract expenses

2011 2010 US$’000 US$’000 Accrued contract expenses ...... 1,268,818 1,272,942 Reserve for contract losses ...... — 2,523 1,268,818 1,275,465

The reserve for contract losses in the prior year was to cover costs in excess of revenues on certain contracts.

F-128 Notes to the consolidated financial statements continued For the year ended 31 December 2011

32 Commitments and contingencies Commitments In the normal course of business the Group will obtain surety bonds, letters of credit and guarantees, which are contractually required to secure performance, advance payment or in lieu of retentions being withheld. Some of these facilities are secured by issue of corporate guarantees by the Company in favour of the issuing banks.

At 31 December 2011, the Group had letters of credit of US$5,995,000 (2010: US$2,984,000) and outstanding letters of guarantee, including performance, advance payments and bid bonds, of US$2,185,385,000 (2010: US$2,951,553,000) against which the Group had pledged or restricted cash balances of, in aggregate, US$2,813,000 (2010: US$19,462,000).

At 31 December 2011, the Group had outstanding forward exchange contracts amounting to US$324,221,000 (2010: US$188,561,000).

These commitments consist of future obligations to either acquire or sell designated amounts of foreign currency at agreed rates and value dates (note 34).

2011 2010 US$’000 US$’000 Within one year ...... 23,856 18,031 After one year but not more than five years ...... 44,674 41,239 More than five years ...... 48,987 76,914 117,517 136,184

Included in the above are commitments relating to the lease of an office building extension in Aberdeen, United Kingdom of US$34,041,000 (2010: US$49,232,000).

Minimum lease payments recognised as an operating lease expense during the year amounted to US$37,272,000 (2010: US$35,625,000).

Long-term finance lease commitments are as follows:

Future minimum lease Present payments Finance cost value US$’000 US$’000 US$’000 Land, buildings and leasehold improvements ...... 17,371 1,335 16,036 The commitments are as follows: Within one year ...... 6,225 833 5,392 After one year but not more than five years ...... 11,146 502 10,644 More than five years ...... —— — 17,371 1,335 16,036

Capital commitments At 31 December 2011, the Group had capital commitments of US$479,968,000 (2010: US$90,416,000) excluding the above lease commitments.

F-129 Notes to the consolidated financial statements continued For the year ended 31 December 2011

32 Commitments and contingencies continued

Included in the above are commitments in respect of Production Enhancement Contracts in Mexico on the Magallanes field of US$108,300,000 and Santuario field of US$116,900,000, costs to refurbish the Berantai FPSO of US$89,250,000 (2010: US$52,800,000), further appraisal and development of wells as part of Block PM304 in Malaysia amounting to US$110,600,000 (2010: US$7,269,000), commitments in respect of the Ticleni Production Enhancement Contract in Romania of US$25,000,000 (2010: US$21,046,000), commitments in respect of the construction of a new office building in United Arab Emirates of US$21,436,000 (2010: US$ nil) and commitments in respect of IT projects of US$6,171,000 (2010: US$9,281,000).

33 Related party transactions The consolidated financial statements include the financial statements of Petrofac Limited and the subsidiaries listed in note 35. Petrofac Limited is the ultimate parent entity of the Group.

The following table provides the total amount of transactions which have been entered into with related parties:

Purchases Amounts Amounts Sales to from owed owed related related by related to related parties parties parties parties US$’000 US$’000 US$’000 US$’000 Joint ventures ...... 2011 322,669 187,440 95,075 22,899 2010 101,370 88,796 327 11,098 Associates ...... 2011 14,118 — 4,000 — 2010 — — — — Key management personnel interests ...... 2011 — 1,591 — 267 2010 — 1,688 — 612

All sales to and purchases from joint ventures are made at normal market prices and the pricing policies and terms of these transactions are approved by the Group’s management.

All related party balances will be settled in cash.

Purchases in respect of key management personnel interests of US$1,411,000 (2010: US$1,601,000) reflect the market rate based costs of chartering the services of an aeroplane used for the transport of senior management and Directors of the Group on company business, which is owned by an offshore trust of which the Group Chief Executive of the Company is a beneficiary.

Also included in purchases in respect of key management personnel interests is US$180,000 (2010: US$87,000) relating to client entertainment provided by a business owned by a member of the Group’s key management.

Compensation of key management personnel The following details remuneration of key management personnel of the Group comprising of Executive and Non-executive Directors of the Company and other senior personnel. Further information relating to the individual Directors is provided in the Directors’ remuneration report on pages 91 to 105.

2010 2011 US$’000 US$’000 As restated Short-term employee benefits ...... 19,807 17,381 Other long-term employment benefits ...... 158 142 Share-based payments ...... 8,114 4,159 Fees paid to Non-executive Directors ...... 836 609 28,915 22,291

F-130 Notes to the consolidated financial statements continued For the year ended 31 December 2011

33 Related party transactions continued

Comparatives have been restated to include the invested portion of DBSP awards to be consistent with the current year presentation.

34 Risk management and financial instruments Risk management objectives and policies The Group’s principal financial assets and liabilities, other than derivatives, comprise available-for-sale financial assets, trade and other receivables, amounts due from/to related parties, cash and short-term deposits, work-in- progress, interest-bearing loans and borrowings, trade and other payables and deferred consideration.

The Group’s activities expose it to various financial risks particularly associated with interest rate risk on its variable rate cash and short-term deposits, loans and borrowings and foreign currency risk on both conducting business in currencies other than reporting currency as well as translation of the assets and liabilities of foreign operations to the reporting currency. These risks are managed from time to time by using a combination of various derivative instruments, principally interest rate swaps, caps and forward currency contracts in line with the Group’s hedging policies. The Group has a policy not to enter into speculative trading of financial derivatives.

The Board of Directors of the Company has established an Audit Committee and Risk Committee to help identify, evaluate and manage the significant financial risks faced by the Group and their activities are discussed in detail on pages 82 to 90.

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.

Pre-tax profit Equity 100 basis 100 basis 100 basis 100 basis point point point point increase decrease increase decrease US$’000 US$’000 US$’000 US$’000 31 December 2011 ...... (516) 516 — — 31 December 2010 ...... (710) 710 — —

F-131 Notes to the consolidated financial statements continued For the year ended 31 December 2011

34 Risk management and financial instruments continued

The following table reflects the maturity profile of these financial liabilities and assets:

Year ended 31 December 2011

Within 1-2 2-3 3-4 4-5 More than 1 year years years years years 5 years Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Financial liabilities Floating rates Bank overdrafts (note 27) ...... 36,932 — — — — — 36,932 Term loans (note 27) ...... 23,779 19,566 — — — — 43,345 60,711 19,566 — — — — 80,277 Financial assets Floating rates Cash and short-term deposits (note 22)...... 1,572,338 — — — — — 1,572,338 Restricted cash balances (note 17) . . . 2,506 307 — — — — 2,813 1,574,844 307 — — — — 1,575,151

Year ended 31 December 2010

Within 1-2 2-3 3-4 4-5 More than 1 year years years years years 5 years Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Financial liabilities Floating rates Bank overdrafts (note 27) ...... 28,908 — — — — — 28,908 Term loans (note 27) ...... 18,527 23,823 20,562 — — — 62,912 47,435 23,823 20,562 — — — 91,820 Financial assets Floating rates Cash and short-term deposits (note 22)...... 1,063,005 — — — — — 1,063,005 Restricted cash balances (note 17) . . . 19,196 266 — — — — 19,462 1,082,201 266 — — — — 1,082,467

Financial liabilities in the above table are disclosed gross of debt acquisition costs and effective rate adjustments of US$3,116,000 (2010: US$4,159,000).

Derivative instruments designated as cash flow hedges At 31 December 2011, the Group held no derivative instruments, designated as cash flow hedges in relation to floating rate interest-bearing loans and borrowings (2010: nil).

F-132 Notes to the consolidated financial statements continued For the year ended 31 December 2011

34 Risk management and financial instruments continued

2011 2010 %of %of foreign foreign currency currency denominated denominated items items Revenues ...... 36.4% 41.6% Costs ...... 57.7% 62.2% Current financial assets ...... 32.5% 34.8% Non-current financial assets ...... 0.0% 0.0% Current financial liabilities ...... 34.7% 51.2% Non-current financial liabilities ...... 54.2% 59.4%

2011 2010 Average rate Closing rate Average rate Closing rate Sterling ...... 1.60 1.55 1.54 1.56 Kuwaiti dinar ...... 3.62 3.59 3.49 3.55 Euro ...... 1.40 1.30 1.32 1.34

Pre-tax profit Equity US 10%מ US +10% US 10%מ US +10% dollar rate dollar rate dollar rate dollar rate increase decrease increase decrease US$’000 US$’000 US$’000 US$’000 31 December 2011 ...... (3,814) 3,814 49,659 (49,659) 31 December 2010 ...... (3,750) 3,750 6,272 (6,272)

F-133 Notes to the consolidated financial statements continued For the year ended 31 December 2011

34 Risk management and financial instruments continued

Derivative instruments designated as cash flow hedges At 31 December 2011, the Group had foreign exchange forward contracts as follows:

Contract value Fair value (undesignated) Fair value (designated) Net unrealised gain/(loss) 2011 2010 2011 2010 2011 2010 2011 2010 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Euro purchases ...... 222,617 171,072 — (1,794) (9,748) (2,046) (7,729) (1,827) Sterling purchases ...... 40,156 14,405 — (135) (1,815) 1,583 (1,425) 1,695 Yen (sales) purchases .... (4,030) 1,721 30 128 29 76 44 117 Singapore dollar purchases ...... 45,683 — (471) — (1,302) — (1,180) — Swiss francs purchases . . . — 1,363 — — — 175 — 14 (10,290) (1)

The above foreign exchange contracts mature and will affect income between January 2012 and July 2013 (2010: between January 2011 and July 2013).

At 31 December 2011, the Group had cash and short-term deposits designated as cash flow hedges with a fair value loss of US$9,440,000 (2010: US$1,633,000 loss) as follows:

Fair value Net unrealised gain/(loss) 2011 2010 2011 2010 US$’000 US$’000 US$’000 US$’000 Euro cash and short-term deposits ...... 180,520 15,730 (9,206) (1,798) Sterling cash and short-term deposits ...... 15,098 2,086 (377) (120) Yen cash and short-term deposits ...... 3,251 4,510 145 278 Swiss francs cash and short-term deposits ...... — 660 — 7 (9,440) (1,633)

During 2011, changes in fair value losses of US$14,117,000 (2010: losses US$19,456,000) relating to these derivative instruments and financial assets were taken to equity and US$3,979,000 of gains (2010: US$16,764,000 gains) were recycled from equity into cost of sales in the income statement. The forward points and ineffective portions of the above foreign exchange forward contracts and loss on un-designated derivatives of US$5,881,000 (2010: US$3,409,000 loss) were recognised in the income statement (note 4b).

Commodity price risk – oil prices The Group is exposed to the impact of changes in oil & gas prices on its revenues and profits generated from sales of crude oil & gas. The Group’s policy is to manage its exposure to the impact of changes in oil & gas prices using derivative instruments, primarily swaps and collars. Hedging is only undertaken once sufficiently reliable and regular long-term forecast production data is available.

During the year the Group entered into various crude oil swaps and zero cost collars hedging oil production of 163,766 barrels (bbl) (2010: 176,400 bbl) with maturities ranging from January 2012 to December 2012. In addition, fuel oil swaps were also entered into for hedging gas production of 21,100 metric tons (MT) (2010: 43,750MT) with maturities from January 2012 to September 2012.

The fair value of oil derivatives at 31 December 2011 was US$636,000 liability (2010: US$1,163,000 liability) with net unrealised losses deferred in equity of US$332,000. During the year, losses of US$304,000 (2010: US$152,000 loss) were recycled from equity into the consolidated income statement on the occurrence of the hedged transactions and a gain in the fair value recognised in equity of US$527,000 (2010: US$1,163,000 loss).

F-134 Notes to the consolidated financial statements continued For the year ended 31 December 2011

34 Risk management and financial instruments continued

Pre-tax profit Equity US$/bbl 10מ US$/bbl +10 US$/bbl 10מ US$/bbl +10 increase decrease increase decrease US$’000 US$’000 US$’000 US$’000 31 December 2011 ...... (1,050) 1,050 (1,716) 1,716 31 December 2010 ...... (194) 194 (802) 802

Credit risk The Group trades only with recognised, creditworthy third parties. Business Unit Risk Review Committees (BURRC) have been set up by the Board of Directors to evaluate the creditworthiness of each individual third- party at the time of entering into new contracts. Limits have been placed on the approval authority of the BURRC above which the approval of the Board of Directors of the Company is required. Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary. At 31 December 2011, the Group’s five largest customers accounted for 47.1% of outstanding trade receivables and work in progress (2010: 72.0%).

Liquidity risk The Group’s primary objective is to ensure sufficient liquidity to support future growth. Our Integrated Energy Services strategy includes the provision of financial capital and the potential impact on the Group’s capital structure is reviewed regularly. The Group is not exposed to any external capital constraints. The maturity profiles of the Group’s financial liabilities at 31 December 2011 are as follows:

Year ended 31 December 2011

Contractual 6 months 6-12 1-2 2-5 More than undiscounted Carrying or less months years years 5 years cash flows amount US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Financial liabilities Interest-bearing loans and borrowings . . 48,346 12,365 19,566 — — 80,277 77,161 Finance lease creditors ...... — 6,225 11,146 — — 17,371 16,036 Trade and other payables (excluding advances from customers) ...... 958,936 15,609 — — — 974,545 974,545 Due to related parties ...... 23,166 — — — — 23,166 23,166 Deferred consideration ...... 1,554 1,975 13,094 — — 16,623 16,268 Derivative instruments ...... 19,423 3,043 — — — 22,466 22,466 Interest payable ...... 107 — — — — 107 107 Interest payments ...... 356 263 158 — — 777 — 1,051,888 39,480 43,964 — — 1,135,332 1,129,749

F-135 Notes to the consolidated financial statements continued For the year ended 31 December 2011

34 Risk management and financial instruments continued

Year ended 31 December 2010

Contractual 6 months 6-12 1-2 2-5 More than undiscounted Carrying or less months years years 5 years cash flows amount US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Financial liabilities Interest-bearing loans and borrowings ...... 37,776 9,659 23,823 20,562 — 91,820 87,661 Trade and other payables (excluding advances from customers) ...... 551,233 58,159 — — — 609,392 609,392 Due to related parties ...... 11,710 — — — — 11,710 11,710 Deferred consideration ...... 24,595 — 11,279 — — 35,874 35,874 Derivative instruments ...... 11,034 1,163 174 — — 12,371 12,371 Interest payable ...... 9 — — — — 9 9 Interest payments ...... 421 388 632 206 — 1,647 — 636,778 69,369 35,908 20,768 — 762,823 757,017

The Group uses various funded facilities provided by banks and its own financial assets to fund the above mentioned financial liabilities.

Capital management The Group’s policy is to maintain a healthy capital base to sustain future growth and maximise shareholder value.

2011 2010 US$’000 US$’000 Cash and short-term deposits ...... 1,572,338 1,063,005 Interest-bearing loans and borrowings(A) ...... (77,161) (87,661) Net cash(B) ...... 1,495,177 975,344 Equity attributable to Petrofac Limited shareholders(C) ...... 1,110,736 776,462 Profit for the year attributable to Petrofac Limited shareholders(D) ...... 539,425 557,817 Gross gearing ratio(A/C) ...... 6.9% 11.3% Net gearing ratio(B/C) ...... Net cash Net cash position position Shareholders’ return on investment(D/C) ...... 48.6% 71.8%

F-136 Notes to the consolidated financial statements continued For the year ended 31 December 2011

34 Risk management and financial instruments continued

Carrying amount Fair value 2011 2010 2011 2010 US$’000 US$’000 US$’000 US$’000 Financial assets Cash and short-term deposits ...... 1,572,338 1,063,005 1,572,338 1,063,005 Restricted cash ...... 2,813 19,462 2,813 19,462 Available-for-sale financial assets ...... — 101,494 — 101,494 Seven Energy warrants ...... 17,616 11,969 17,616 11,969 Forward currency contracts – designated as cash flow hedge . . 8,376 7,961 8,376 7,961 Forward currency contracts – undesignated ...... 177 1,234 177 1,234

Financial liabilities Interest-bearing loans and borrowings ...... 77,161 87,661 80,277 91,820 Deferred consideration ...... 16,268 35,874 16,268 35,874 Oil derivative ...... 636 1,163 636 1,163 Forward currency contracts – designated as cash flow hedge . . 21,212 8,173 21,212 8,173 Forward currency contracts – undesignated ...... 618 3,035 618 3,035

Fair values of financial assets and liabilities Market values have been used to determine the fair values of available-for-sale financial assets, forward currency contracts and oil derivatives. The fair value of warrants over equity instruments in Seven Energy has been calculated using a Black Scholes option valuation model (note 14). The fair values of long-term interest-bearing loans and borrowings are equivalent to their amortised costs determined as the present value of discounted future cash flows using the effective interest rate. The Company considers that the carrying amounts of trade and other receivables, work-in-progress, trade and other payables, other current and non-current financial assets and liabilities approximate their fair values and are therefore excluded from the above table.

Fair value hierarchy The following financial instruments are measured at fair value using the hierarchy below for determination and disclosure of their respective fair values:

F-137 Notes to the consolidated financial statements continued For the year ended 31 December 2011

34 Risk management and financial instruments continued

Assets measured at fair value Year ended 31 December 2011

Tier 1 Tier 2 2011 US$’000 US$’000 US$’000 Financial assets Seven Energy warrants ...... — 17,616 17,616 Forward currency contracts – designated as cash flow hedge ...... — 8,376 8,376 Forward currency contracts – undesignated ...... — 177 177

Financial liabilities Forward currency contracts – designated as cash flow hedge ...... — 21,212 21,212 Forward currency contracts – undesignated ...... — 618 618 Oil derivative ...... — 636 636

Year ended 31 December 2010

Tier 1 Tier 2 2010 US$’000 US$’000 US$’000 Financial assets Available-for-sale financial assets ...... 243 101,251 101,494 Seven Energy warrants ...... — 11,969 11,969 Forward currency contracts – designated as cash flow hedge ...... — 7,961 7,961 Forward currency contracts – undesignated ...... — 1,234 1,234

Financial liabilities Forward currency contracts – designated as cash flow hedge ...... — 8,173 8,173 Forward currency contracts – undesignated ...... — 3,035 3,035 Oil derivative ...... — 1,163 1,163

35 Subsidiaries and joint ventures At 31 December 2011, the Group had investments in the following subsidiaries and incorporated joint ventures:

Proportion of nominal value of issued shares controlled by the Group Name of company Country of incorporation 2011 2010 Trading subsidiaries Petrofac Inc...... USA *100 *100 Petrofac International Ltd ...... Jersey *100 *100 Petrofac Energy Development UK Limited . . England *100 *100 Petrofac Energy Developments International Limited ...... Jersey *100 *100 Petrofac UK Holdings Limited ...... England *100 *100 Petrofac Facilities Management International Limited ...... Jersey *100 *100 Petrofac Services Limited ...... England *100 *100 Petrofac Training International Limited ..... Jersey *100 *100 Petroleum Facilities E & C Limited ...... Jersey *100 *100 Jermyn Insurance Company Limited ...... Guernsey *100 *100 Atlantic Resourcing Limited ...... Scotland 100 100 Petrofac Algeria EURL ...... Algeria 100 100 Petrofac Engineering India Private Limited . . India 100 100

F-138 Notes to the consolidated financial statements continued For the year ended 31 December 2011

35 Subsidiaries and joint ventures continued

Proportion of nominal value of issued shares controlled by the Group Name of company Country of incorporation 2011 2010 Trading subsidiaries continued Petrofac Engineering Services India Private Limited ...... India 100 100 Petrofac Engineering Limited ...... England 100 100 Petrofac Offshore Management Limited ..... Jersey 100 100 Petrofac FZE ...... United Arab Emirates 100 100 Petrofac Facilities Management Group Limited ...... Scotland 100 100 Petrofac Facilities Management Limited .... Scotland 100 100 Petrofac International Nigeria Ltd ...... Nigeria 100 100 Petrofac Pars (PJSC) ...... Iran 100 100 Petrofac Iran (PJSC) ...... Iran 100 100 Plant Asset Management Limited ...... Scotland 100 100 PFMAP Sendirian Berhad ...... Malaysia 100 100 Petrofac (Malaysia-PM304) Limited ...... England 100 100 Petrofac South East Asia Pte Ltd ...... Singapore 100 — Petrofac Netherlands Cooperatief U.A...... Netherlands 100 — Petrofac Netherlands Holding B.V...... Netherlands 100 — Petrofac Treasury B.V...... Netherlands 100 — Petrofac Kazakhstan B.V...... Netherlands 100 — PTS B.V...... Netherlands 100 — Petrofac Mexico SA de CV ...... Mexico 100 — Petrofac Mexico Servicios SA de CV ...... Mexico 100 — Petrofac Energy Developments Sdn Bhd .... Malaysia 100 — Petrofac FPF003 Pte Ltd ...... Singapore 100 — Petrofac FPF004 Limited ...... Jersey 100 — Petrofac FPF005 Limited ...... Malaysia 100 — Petrofac GSA Limited ...... Jersey 100 — Petrofac Training Group Limited ...... Scotland 100 100 Petrofac Training Holdings Limited ...... Scotland 100 100 Petrofac Training Limited ...... Scotland 100 100 Petrofac Training Inc...... USA 100 100 Monsoon Shipmanagement Limited ...... Jersey 100 100 Petrofac E&C International Limited ...... United Arab Emirates 100 100 Petrofac Saudi Arabia Limited ...... Saudi Arabia 100 100 Petrofac Energy Developments (Ohanet) Jersey Limited ...... Jersey 100 100 Petrofac Energy Developments (Ohanet) LLC...... USA 100 100 Petrofac (Cyprus) Limited ...... Cyprus 100 100 PKT Technical Services Ltd ...... Russia **50 **50 PKT Training Services Ltd ...... Russia 100 100 Pt PCI Indonesia ...... Indonesia 80 80 Petrofac Training Institute Pte Limited ...... Singapore 100 100 Petrofac Training Sdn Bhd ...... Malaysia 100 100 Sakhalin Technical Training Centre ...... Russia 80 80 Petrofac Norge AS ...... Norway 100 100 SPD Group Limited ...... British Virgin Islands 100 51 SPD UK Limited ...... Scotland 100 51 SPDLLC...... United Arab Emirates **49 **25 PT. Petrofac IKPT International ...... Indonesia 51 51 Petrofac Kazakhstan Limited ...... England 100 100 Petrofac International (UAE) LLC ...... United Arab Emirates 100 100 Petrofac E&C Oman LLC ...... Oman 100 100 Petrofac International South Africa (Pty) Limited ...... South Africa 100 100

F-139 Notes to the consolidated financial statements continued For the year ended 31 December 2011

35 Subsidiaries and joint ventures continued

Proportion of nominal value of issued shares controlled by the Group Name of company Country of incorporation 2011 2010 Trading subsidiaries continued Eclipse Petroleum Technology Limited ..... England 100 100 Caltec Limited ...... England 100 100 i Perform Limited ...... Scotland 100 100 Petrofac FPF1 Limited ...... Jersey 100 100 Petrofac Platform Management Services Limited ...... Jersey 100 100 Petrokyrgyzstan Limited ...... Jersey 100 100 Scotvalve Services Limited ...... Scotland 100 100 Stephen Gillespie Consultants Limited ...... Scotland 100 100 CO2DeepStore Limited ...... Scotland 100 100 CO2DeepStore Holdings Limited ...... Jersey 100 100 CO2DeepStore (Aspen) Limited ...... England 100 100 TNEI Services Limited ...... England 100 100 Petrofac E&C Sdn Bhd ...... Malaysia 100 100 Petrofac FPSO Holding Limited ...... Jersey 100 100 The New Energy Industries Limited ...... England 100 100 Petrofac Information Services Private Limited ...... India 100 100 Petrofac Solutions & Facilities Support S.R.L ...... Romania 100 100

Joint Ventures Costain Petrofac Limited ...... England 50 50 Kyrgyz Petroleum Company ...... Kyrgyz Republic 50 50 MJVI Sendirian Berhad ...... Brunei 50 50 Spie Capag – Petrofac International Limited ...... Jersey 50 50 TTE Petrofac Limited ...... Jersey 50 50 China Petroleum Petrofac Engineering Services Cooperatif U.A...... Netherlands 49 — Berantai Floating Production Limited ...... Malaysia 51 — Petrofac Emirates LLC ...... United Arab Emirates 49 49

Dormant subsidiaries Joint Venture International Limited ...... Scotland 100 100 Montrose Park Hotels Limited ...... Scotland 100 100 RGIT Ethos Health & Safety Limited ...... Scotland 100 100 Scota Limited ...... Scotland 100 100 Monsoon Shipmanagement Limited ...... Cyprus 100 100 Rubicon Response Limited ...... Scotland 100 100 Petrofac Services Inc ...... USA *100 *100 Petrofac Training (Trinidad) Limited ...... Trinidad 100 100 Petrofac ESOP Trustees Limited ...... Jersey *100 *100

* Directly held by Petrofac Limited **Companies consolidated as subsidiaries on the basis of control. The Company’s interest in joint venture operations are disclosed on page F-94.

F-140 Independent Auditors’ report to the members of Petrofac Limited

We have audited the group financial statements of Petrofac Limited (‘the Company’) and its subsidiaries (together ‘the group’) for the year ended 31 December 2010 which comprise the consolidated income statement, the consolidated statement of comprehensive income, the consolidated statement of financial position, the consolidated cash flow statement, the consolidated statement of changes in equity and the related notes 1 to 35. The financial reporting framework that has been applied in their preparation is applicable Jersey law and International Financial Reporting Standards.

This report is made solely to the Company’s members, as a body, in accordance with Article 113A of the Companies (Jersey) Law 1991 and our engagement letter dated 15 February 2011. Our audit work has been undertaken so that we might state to the Company’s members those matters we are required to state to them in an auditor’s report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company’s members as a body, for our audit work, for this report, or for the opinions we have formed.

Respective responsibilities of directors and auditor As explained more fully in the statement of directors’ responsibilities set out on page 96, the directors are responsible for the preparation of the group financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the group financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors.

In addition the Company has also instructed us to: • review the statement of directors’ responsibilities in relation to going concern as set out on page 96, which for a premium listed UK incorporated company is specified for review by the Listing Rules of the Financial Services Authority • report as to whether the information given in the corporate governance report with respect to internal control and risk management systems in relation to financial reporting processes and about share capital structures is consistent with the financial statements

Opinion on financial statements In our opinion the group financial statements: • give a true and fair view of the state of the group’s affairs as at 31 December 2010 and of its profit for the year then ended • have been properly prepared in accordance with International Financial Reporting Standards • have been prepared in accordance with the requirements of the Companies (Jersey) Law 1991

Opinion on other matter In our opinion, the information given in the corporate governance report set out on pages 71 to 78 with respect to internal control and risk management systems in relation to financial reporting processes and about share capital structures is consistent with the financial statements.

F-141 Matters on which we are required to report by exception We have nothing to report in respect of the following matters: • where the Companies (Jersey) Law 1991 requires us to report to you if, in our opinion: • proper accounting records have not been kept, or proper returns adequate for our audit have not been received from branches not visited by us • the financial statements are not in agreement with the accounting records and returns • we have not received all the information and explanations we require for our audit • under the Listing Rules we are required to review the part of the corporate governance report relating to the Company’s compliance with the nine provisions of the June 2008 Combined Code specified for our review • where the Company instructed us to review the statement of directors’ responsibilities, set out on page 96, in relation to going concern

Other matter We have reported separately on the parent company financial statements of Petrofac Limited for the year ended 31 December 2010 and on the information in the remuneration report that is described as having been audited.

Justine Belton for and on behalf of Ernst & Young LLP London

4 March 2011

Notes: 1 The maintenance and integrity of the Petrofac Limited web site is the responsibility of the directors; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the website. 2 Legislation in Jersey governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

F-142 Consolidated income statement For the year ended 31 December 2010

Restated 2010 2009 Notes US$’000 US$’000 Revenue ...... 4a 4,354,217 3,655,426 Cost of sales ...... 4b (3,595,142) (3,038,250) Gross profit ...... 759,075 617,176 Selling, general and administration expenses ...... 4c (221,449) (186,293) Gain on EnQuest demerger ...... 11 124,864 — Other income ...... 4f 5,013 4,075 Other expenses ...... 4g (4,053) (2,998) Profit from operations before tax and finance income/(costs) ...... 663,450 431,960 Finance costs ...... 5 (5,131) (5,582) Finance income ...... 5 10,209 11,942 Share of loss of associate ...... 14 (131) — Profit before tax ...... 668,397 438,320 Income tax expense ...... 6 (110,545) (84,515) Profit for the year ...... 557,852 353,805

Attributable to: Petrofac Limited shareholders ...... 557,817 353,603 Non-controlling interests ...... 35 202 557,852 353,805 Earnings per share (US cents) ...... 7 – Basic (excluding gain on EnQuest demerger) ...... 127.76 104.78 – Diluted (excluding gain on EnQuest demerger) ...... 126.09 103.19

– Basic (including gain on EnQuest demerger) ...... 164.61 104.78 – Diluted (including gain on EnQuest demerger) ...... 162.46 103.19

The attached notes 1 to 35 form part of these consolidated financial statements.

F-143 Consolidated statement of comprehensive income For the year ended 31 December 2010

Restated 2010 2009 Notes US$’000 US$’000 Profit for the year ...... 557,852 353,805 Foreign currency translation ...... 25 (908) 15,087 Foreign currency translation recycled to income statement in the year on EnQuest demerger ...... 11 45,818 — Net gains on maturity of cash flow hedges recycled in the period ...... 25 (16,612) (4,303) Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... 25 (18,958) 29,229 Net changes in the fair value of available-for-sale financial assets ...... 25 70 — Disposal of available-for-sale financial assets ...... 25 (74) — Other comprehensive income ...... 9,336 40,013 Total comprehensive income for the period ...... 567,188 393,818

Attributable to: Petrofac Limited shareholders ...... 567,153 393,616 Non-controlling interests ...... 35 202 567,188 393,818

The attached notes 1 to 35 form part of these consolidated financial statements.

F-144 Consolidated statement of financial position At 31 December 2010

Restated 2010 2009 Notes US$’000 US$’000 Assets Non-current assets Property, plant and equipment ...... 9 287,158 677,996 Goodwill ...... 12 105,832 97,922 Intangible assets ...... 13 85,837 73,107 Investment in associates ...... 14 16,349 — Available-for-sale financial assets ...... 16 101,494 539 Other financial assets ...... 17 2,223 12,535 Deferred income tax assets ...... 6c 26,301 49,726 625,194 911,825 Current assets Inventories ...... 18 7,202 9,798 Work in progress ...... 19 803,986 333,698 Trade and other receivables ...... 20 1,056,759 878,670 Due from related parties ...... 32 327 18,260 Other financial assets ...... 17 42,350 30,957 Income tax receivable ...... 2,525 — Cash and short-term deposits ...... 21 1,063,005 1,417,363 2,976,154 2,688,746 Total assets ...... 3,601,348 3,600,571 Equity and liabilities Equity attributable to Petrofac Limited shareholders Share capital ...... 22 6,914 8,638 Share premium ...... 992 69,712 Capital redemption reserve ...... 10,881 10,881 Shares to be issued ...... 994 1,988 Treasury shares ...... 23 (65,317) (56,285) Other reserves ...... 25 34,728 25,394 Retained earnings ...... 787,270 834,382 776,462 894,710 Non-controlling interests ...... 2,592 2,819 Total equity ...... 779,054 897,529 Non-current liabilities Interest-bearing loans and borrowings ...... 26 40,226 59,195 Provisions ...... 27 45,441 92,103 Other financial liabilities ...... 28 11,453 27,485 Deferred income tax liabilities ...... 6c 48,086 42,192 145,206 220,975 Current liabilities Trade and other payables ...... 29 1,021,436 977,017 Due to related parties ...... 32 11,710 57,326 Interest-bearing loans and borrowings ...... 26 47,435 58,071 Other financial liabilities ...... 28 37,054 3,634 Income tax payable ...... 105,559 88,219 Billings in excess of cost and estimated earnings ...... 19 178,429 461,144 Accrued contract expenses ...... 30 1,275,465 836,656 2,677,088 2,482,067 Total liabilities ...... 2,822,294 2,703,042 Total equity and liabilities ...... 3,601,348 3,600,571

The financial statements on pages F-121 to F-179 were approved by the Board of Directors on 4 March 2011 and signed on its behalf by Keith Roberts – Chief Financial Officer.

The attached notes 1 to 35 form part of these consolidated financial statements.

F-145 Consolidated statement of cash flows For the year ended 31 December 2010

Restated 2010 2009 Notes US$’000 US$’000 Operating activities Profit before tax including gain on EnQuest demerger ...... 668,397 438,320 Gain on EnQuest demerger ...... (124,864) — 543,533 438,320 Non-cash adjustments to reconcile profit before tax to net cash flows: Depreciation, amortisation, impairment and write off ...... 4b,4c 95,903 117,780 Share-based payments ...... 4d 14,784 13,263 Difference between other long-term employment benefits paid and amounts recognised in the income statement ...... 6,074 7,905 Net finance income ...... 5 (5,078) (6,360) Loss/(gain) on disposal of property, plant and equipment ...... 4b,4f,4g 315 (784) Gain on disposal of intangible assets ...... 4f (2,338) — Other non-cash items, net ...... 13,319 (3,233) 666,512 566,891 Working capital adjustments: Trade and other receivables ...... (266,757) (176,773) Work in progress ...... (470,288) (81,003) Due from related parties ...... 17,933 (15,353) Inventories ...... (2,982) (5,721) Other current financial assets ...... (12,661) (4,775) Trade and other payables ...... 167,707 479,902 Billings in excess of cost and estimated earnings ...... (282,715) 175,617 Accrued contract expenses ...... 438,809 284,795 Due to related parties ...... (45,616) 56,767 Other current financial liabilities ...... 6,045 177 215,987 1,280,524 Other non-current items, net ...... (8,720) (4,265) Cash generated from operations ...... 207,267 1,276,259 Interest paid ...... (1,948) (3,351) Income taxes paid, net ...... (99,030) (87,714) Net cash flows from operating activities ...... 106,289 1,185,194 Investing activities Purchase of property, plant and equipment ...... (115,345) (317,174) Acquisition of subsidiaries, net of cash acquired ...... 10 (15,110) — Purchase of other intangible assets ...... 13 (153) (10,375) Purchase of intangible oil & gas assets ...... 13 (15,644) (29,230) Cash outflow on EnQuest demerger (including transaction costs) ...... (17,783) — Investment in associates ...... 14 (8,459) — Purchase of available-for-sale financial assets ...... 16 (101,494) (106) Proceeds from disposal of property, plant and equipment ...... 3,219 1,333 Proceeds from disposal of available-for-sale financial assets ...... 539 95 Proceeds from sale of intangible assets ...... 6,018 — Interest received ...... 10,257 12,158 Net cash flows used in investing activities ...... (253,955) (343,299) Financing activities Repayment of interest-bearing loans and borrowings ...... (32,458) (9,958) Proceeds from capital injection by non-controlling interest ...... — 2,408 Treasury shares purchased ...... 23 (36,486) — Equity dividends paid ...... (132,244) (98,995) Net cash flows used in financing activities ...... (201,188) (106,545) Net (decrease)/increase in cash and cash equivalents ...... (348,854) 735,350 Net foreign exchange difference ...... (7,793) 6,235 Cash and cash equivalents at 1 January ...... 1,390,744 649,159 Cash and cash equivalents at 31 December ...... 21 1,034,097 1,390,744

The attached notes 1 to 35 form part of these consolidated financial statements.

F-146 Consolidated statement of changes in equity For the year ended 31 December 2010

Attributable to shareholders of Petrofac Limited Issued Capital Shares to *Treasury Other Non- share Share redemption be shares reserves Retained controlling Total capital premium reserve issued US$’000 US$’000 earnings Total interests equity US$’000 US$’000 US$’000 US$’000 (note 23) (note 25) US$’000 US$’000 US$’000 US$’000 Balance at 1 January 2010 as restated ...... 8,638 69,712 10,881 1,988 (56,285) 25,394 834,382 894,710 2,819 897,529 Net profit for the year ...... — — — — — — 557,817 557,817 35 557,852 Other comprehensive income .... — — — — — 9,336 — 9,336 — 9,336 Total comprehensive income for the year ...... — — — — — 9,336 557,817 567,153 35 567,188 Shares issued as payment of consideration on acquisition . . . 4 2,452 — (994) — — — 1,462 — 1,462 Share-based payments charge (note 24) ...... — — — — — 14,784 — 14,784 — 14,784 Shares vested during the year (note 23)...... — — — — 27,454 (26,170) (1,284) — — — Transfer to reserve for share-based payments (note 24) ...... — — — — — 12,750 — 12,750 — 12,750 Treasury shares purchased (note 23) ...... — — — — (36,486) — — (36,486) — (36,486) Deferred tax on share based payments reserve ...... — — — — — (1,366) — (1,366) — (1,366) EnQuest demerger share split and redemption (note 11) ...... (1,728) — — — — — 1,728 — — — Distribution on EnQuest demerger (note 11) ...... — (71,172) — — — — (473,325)(544,497) — (544,497) Dividends (note 8) ...... — — — — — — (132,048)(132,048) — (132,048) Movement in non-controlling interests ...... — — — — — — — — (262) (262) Balance at 31 December 2010 ... 6,914 992 10,881 994 (65,317) 34,728 787,270 776,462 2,592 779,054

F-147 Consolidated statement of changes in equity continued For the year ended 31 December 2010

Attributable to shareholders of Petrofac Limited Other Issued Capital Shares to *Treasury reserves Non- share Share redemption be shares US$’000 Retained controlling Total capital premium reserve issued US$’000 (note earnings Total interests equity US$’000 US$’000 US$’000 US$’000 (note 23) 25) US$’000 US$’000 US$’000 US$’000 Balance at 1 January 2009 ...... 8,636 68,203 10,881 1,988 (69,333) (39,292) 577,739 558,822 209 559,031 Net profit for the year as reported ...... — — — — — — 353,603 353,603 9,428 363,031 Other comprehensive income as reported ...... — — — — — 35,813 — 35,813 4,200 40,013 Total comprehensive income for the year as reported ...... — — — — — 35,813 353,603 389,416 13,628 403,044 Restatement ...... — — — — — 4,200 — 4,200 (13,426) (9,226) Total comprehensive income for the year as restated ...... — — — — — 40,013 353,603 393,616 202 393,818 Shares issued on acquisition ..... 2 1,509 — — — — — 1,511 — 1,511 Share-based payments charge (note 24) ...... — — — — — 13,263 — 13,263 — 13,263 Shares vested during the year (note 23) ...... — — — — 13,048 (12,617) (431) — — — Transfer to reserve for share-based payments (note 24) ...... — — — — — 10,942 — 10,942 — 10,942 Deferred tax on share based payments reserve ...... — — — — — 13,085 — 13,085 — 13,085 Capital injection by non- controlling interests ...... — — — — — — — — 2,408 2,408 Dividends (note 8) ...... — — — — — — (96,529) (96,529) — (96,529) Balance at 31 December 2009 as restated ...... 8,638 69,712 10,881 1,988 (56,285) 25,394 834,382 894,710 2,819 897,529

* Shares held by Petrofac Employee Benefit Trust.

The attached notes 1 to 35 form part of these consolidated financial statements.

F-148 Notes to the consolidated financial statements For the year ended 31 December 2010

1 Corporate information The consolidated financial statements of Petrofac Limited (the ‘Company’) for the year ended 31 December 2010 were authorised for issue in accordance with a resolution of the directors on 4 March 2011.

Petrofac Limited is a limited liability company registered and domiciled in Jersey under the Companies (Jersey) Law 1991 and is the holding company for the international group of Petrofac subsidiaries (together ‘the group’). The Company’s 31 December 2010 financial statements are shown on pages 146 to 158. The group’s principal activity is the provision of facilities solutions to the oil & gas production and processing industry.

A full listing of all group companies, and joint venture companies, is contained in note 35 to these consolidated financial statements.

2 Summary of significant accounting policies Basis of preparation The consolidated financial statements have been prepared on a historical cost basis, except for derivative financial instruments and available-for-sale financial assets which have been measured at fair value. The presentation currency of the consolidated financial statements is United States Dollars and all values in the financial statements are rounded to the nearest thousand (US$’000) except where otherwise stated. The directors have re-considered the nature of the contractual commitments to a joint venture on a lump sum construction contract in the Engineering & Construction reporting segment and as a result, the amount of US$9,226,000 shown as part of non-controlling interest in December 2009 in the income statement has been reclassified to Cost of Sales. Similarly US$4,200,000 shown within Other Comprehensive Income has been shown as attributable to Petrofac. US$9,226,000 in the statement of financial position has been reclassified as trade and other payables.

Basis of consolidation The consolidated financial statements comprise the financial statements of Petrofac Limited and its subsidiaries. The financial statements of its subsidiaries are prepared for the same reporting year as the Company and where necessary, adjustments are made to the financial statements of the group’s subsidiaries to bring their accounting policies into line with those of the group.

Subsidiaries are consolidated from the date on which control is transferred to the group and cease to be consolidated from the date on which control is transferred out of the group. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities. All intra-group balances and transactions, including unrealised profits, have been eliminated on consolidation.

Non-controlling interests in subsidiaries consolidated by the group are disclosed separately from the group’s equity and income statement. Prior to 1 January 2010 losses incurred by the group were attributed to non- controlling interests until the balance is reduced to nil. Any further excess losses were attributed to the parent, unless there was a binding obligation on the part of the non-controlling interest to cover these. Losses prior to 1 January 2010 were not reallocated between non-controlling interests and the parent shareholders.

New standards and interpretations The group has adopted new and revised Standards and Interpretations issued by the International Accounting Standards Board (IASB) and the International Financial Reporting Interpretations Committee (IFRIC) of the IASB that are relevant to its operations and effective for accounting periods beginning on or after 1 January 2010. The principal effects of the adoption of these new and amended standards and interpretations are discussed below:

F-149 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

IFRS 3 ‘Business Combinations (Revised)’ the revised standard increases the number of transactions to which it must be applied including business combinations of mutual entities and combinations without consideration. IFRS 3 (revised) introduces significant changes in the accounting for business combinations such as valuation of non-controlling interest, business combination achieved in stages, the initial recognition and subsequent measurement of a contingent consideration and the accounting for transaction costs. These changes will have a significant impact on profit or loss reported in the period of an acquisition, the amount of goodwill recognised in a business combination and profit or loss reported in future periods.

IAS 27 ‘Consolidated and Separate Financial Statements (Amendments)’ the amended standard requires that a change in the ownership interest of a subsidiary (without loss of control) is accounted for as a transaction with owners in their capacity as owners and these transactions will no longer give rise to goodwill or gains and losses. The standard also specifies the accounting when control is lost and any retained interest is remeasured to fair value with gains or losses recognised in profit or loss.

IFRIC 17 ‘Distributions of Non-cash Assets to owners’ this interpretation provides guidance in respect of accounting for non-cash asset distributions to shareholders. This interpretation is effective for periods beginning on or after 1 July 2009. See note 11 for distributions in respect of EnQuest demerger.

IFRS 8 ‘Operating Segments’ the amendment clarifies that segment assets and liabilities need not be reported if they are not used as a measure by the chief operating decision maker. As segment assets and liabilities are not reviewed by the chief operating decision maker for operational and financial decisions, the group has opted not to disclose segment assets and liabilities in note 3.

IAS 36 ‘Impairment of assets’ the amendment clarifies that operating segments as defined in IFRS 8 prior to aggregation for reporting purposes, are the largest unit for allocating goodwill on acquisitions. The amendment has no impact on the group as goodwill impairment testing is performed on cash generating units before aggregation.

Certain new standards, amendments to and interpretations of existing standards have been issued and are effective for the group’s accounting periods beginning on or after 1 January 2011 or later periods which the group has not early adopted. The following are applicable to the group for which the impact on the group’s operating results or financial position will be assessed on adoption of these standards and interpretations: i) IFRS 9 ‘Financial Instruments’ effective for annual periods beginning on or after 1 January 2013, reflects the first phase of the IASB’s work on the replacement of IAS 39 and applies to the classification and measurement of financial assets. It specifies that all financial assets should be initially measured at fair value and gives further guidance on the measurement of debt instruments and equity instruments. In subsequent phases, the IASB will address the classification and measurement of financial liabilities, hedge accounting and derecognition. The completion of this project is expected in early 2011. The management believes that this standard will not have a significant effect on the group’s financial position. ii) IAS 24 ‘Related party disclosures (Revised)’ effective for annual periods beginning on or after 1 January 2011. The revision simplifies the identification of related party relationships, particularly in relation to significant influence and joint control. The management believes that this standard will not have a significant effect on the group’s financial position.

Other amendments resulting from improvements to IFRS to the following standards and interpretations did not have any impact on the accounting policies, financial position or performance of the group:

IAS 1 ‘Presentation of Financial Statements’

IAS 32 ‘Financial Instruments: Presentation – Classification of Rights Issues (Amendment)’

IFRIC 14 ‘Prepayments of a Minimum Funding Requirement (Amendment)’

IFRIC 19 ‘Extinguishing Financial Liabilities with Equity Instruments’

F-150 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

Significant accounting judgements and estimates Judgements In the process of applying the group’s accounting policies, management has made the following judgements, apart from those involving estimations, which have the most significant effect on the amounts recognised in the consolidated financial statements: revenue recognition on fixed-price engineering, procurement and construction contracts: the group recognises revenue on fixed-price engineering, procurement and construction contracts using the percentage-of-completion method, based on surveys of work performed. The group has determined this basis of revenue recognition is the best available measure of progress on such contracts

• project cost to complete estimates: at each statement of financial position date the group is required to estimate costs to complete on fixed price contracts. Estimating costs to complete on such contracts requires the group to make estimates of future costs to be incurred, based on work to be performed beyond the statement of financial position date

• onerous contract provisions: the group provides for future losses on long-term contracts where it is considered probable that the contract costs are likely to exceed revenues in future years. Estimating these future losses involves a number of assumptions about the achievement of contract performance targets and the likely levels of future cost escalation over time

• impairment of goodwill: the group determines whether goodwill is impaired at least on an annual basis. This requires an estimation of the value in use of the cash-generating units to which the goodwill is allocated. Estimating the value in use requires the group to make an estimate of the expected future cash flows from each cash-generating unit and also to determine a suitable discount rate in order to calculate the present value of those cash flows. The carrying amount of goodwill at 31 December 2010 was US$105,832,000 (2009: US$97,922,000) (note 12)

• deferred tax assets: the group recognises deferred tax assets on all applicable temporary differences where it is probable that future taxable profits will be available for utilisation. This requires management to make judgements and assumptions regarding the amount of deferred tax that can be recognised based on the magnitude and likelihood of future taxable profits. The carrying amount of deferred tax assets at 31 December 2010 was US$26,301,000 (2009: US$49,726,000)

• income tax: the Company and its subsidiaries are subject to routine tax audits and also a process whereby tax computations are discussed and agreed with the appropriate authorities. Whilst the ultimate outcome of such tax audits and discussions cannot be determined with certainty, management estimates the level of provisions required for both current and deferred tax on the basis of professional advice and the nature of current discussions with the tax authority concerned

• recoverable value of intangible oil & gas and other intangible assets: the group determines at each statement of financial position date whether there is any evidence of indicators of impairment in the carrying value of its intangible oil & gas and other intangible assets. Where indicators exist, an impairment test is undertaken which requires management to estimate the recoverable value of its intangible assets for example by reference to quoted market values, similar arm’s length transactions involving these assets or value in use calculations

• units of production depreciation: estimated proven plus probable reserves are used in determining the depreciation of oil & gas assets such that the depreciation charge is proportional to the depletion of the remaining reserves over their life of production. These calculations require the use of estimates including the amount of economically recoverable reserves and future oil & gas capital expenditure

F-151 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

Interests in joint ventures The group has a number of contractual arrangements with other parties which represent joint ventures. These take the form of agreements to share control over other entities (‘jointly controlled entities’) and commercial collaborations (‘jointly controlled operations’). The group’s interests in jointly controlled entities are accounted for by proportionate consolidation, which involves recognising the group’s proportionate share of the joint venture’s assets, liabilities, income and expenses with similar items in the consolidated financial statements on a line-by-line basis. Where the group collaborates with other entities in jointly controlled operations, the expenses the group incurs and its share of the revenue earned is recognised in the consolidated income statement. Assets controlled by the group and liabilities incurred by it are recognised in the statement of financial position. Where necessary, adjustments are made to the financial statements of the group’s jointly controlled entities and operations to bring their accounting policies into line with those of the group.

Investment in associates The group’s investment in associates is accounted for using the equity method where the investment is initially carried at cost and adjusted for post acquisition changes in the group’s share of net assets of the associate. Goodwill on the initial investment forms a part of the carrying amount of the investment and is not individually tested for impairment.

The group recognises its share of the net profits after tax and non-controlling interest of the associates in its consolidated income statement. Share of associate’s changes in equity is also recognised in the group’s consolidated statement of changes in equity. Any unrealised gains and losses resulting from transactions between the group and the associate are eliminated to the extent of the interest in associates.

The financial statements of the associate are prepared using the same accounting policies and reporting periods as that of the group.

The carried value of the investment is tested for impairment at each reporting date. Impairment, if any, is determined by the difference between the recoverable amount of the associate and its carried value and is reported within the share of income of an associate in the group’s consolidated income statement.

Foreign currency translation The Company’s functional and presentational currency is United States Dollars. In the financial statements of individual subsidiaries, joint ventures and associates, transactions in currencies other than a company’s functional currency are recorded at the prevailing rate of exchange at the date of the transaction. At the year end, monetary assets and liabilities denominated in foreign currencies are retranslated at the rates of exchange prevailing at the statement of financial position date. Non-monetary assets and liabilities that are measured at historical cost in a foreign currency are translated using the rate of exchange as at the dates of the initial transactions. Non-monetary assets and liabilities measured at fair value in a foreign currency are translated using the rate of exchange at the date the fair value was determined. All foreign exchange gains and losses are taken to the consolidated income statement with the exception of exchange differences arising on monetary assets and liabilities that form part of the group’s net investment in subsidiaries. These are taken directly to statement of changes in equity until the disposal of the net investment at which time they are recognised in the consolidated income statement.

The statement of financial positions of overseas subsidiaries, joint ventures and associates are translated into US Dollars using the closing rate method, whereby assets and liabilities are translated at the rates of exchange prevailing at the statement of financial position date. The income statements of overseas subsidiaries and joint ventures are translated at average exchange rates for the year. Exchange differences arising on the retranslation of net assets are taken directly to other reserves within statement of changes in equity.

On the disposal of a foreign entity, accumulated exchange differences are recognised in the consolidated income statement as a component of the gain or loss on disposal.

F-152 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

Property, plant and equipment Property, plant and equipment is stated at cost less accumulated depreciation and any impairment in value. Cost comprises the purchase price or construction cost and any costs directly attributable to making that asset capable of operating as intended. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Depreciation is provided on a straight-line basis other than on oil & gas assets at the following rates:

Oil & gas facilities 10% - 12.5% Plant and equipment 4% - 33% Buildings and leasehold improvements 5% - 33% (or lease term if shorter) Office furniture and equipment 25% - 100% Vehicles 20% - 33%

Each asset’s estimated useful life, residual value and method of depreciation are reviewed and adjusted if appropriate at each financial year end.

No depreciation is charged on land or assets under construction.

The carrying amount of an item of property, plant and equipment is derecognised on disposal or when no future economic benefits are expected from its use or disposal. The gain or loss arising from the derecognition of an item of property, plant and equipment is included in profit or loss when the item is derecognised. Gains are not classified as revenue.

Non-current assets held for sale Non-current assets or disposal groups are classified as held for sale when it is expected that the carrying amount of an asset will be recovered principally through sale rather than continuing use. Assets are not depreciated when classified as held for sale.

Goodwill Goodwill acquired in a business combination is initially measured at cost, being the excess of the cost of the business combination over the net fair value of the identifiable assets, liabilities and contingent liabilities of the entity at the date of acquisition. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually, or more frequently if events or changes in circumstances indicate that such carrying value may be impaired. All transaction costs associated with business combinations post 1 January 2010 are charged to the consolidated income statement in the year of such combination.

For the purpose of impairment testing, goodwill acquired is allocated to the cash-generating units that are expected to benefit from the synergies of the combination. Each unit or units to which goodwill is allocated represents the lowest level within the group at which the goodwill is monitored for internal management purposes and is not larger than an operating segment determined in accordance with IFRS8 ‘Operating Segments’.

F-153 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

Deferred consideration payable on acquisition When, as part of a business combination, the group defers a proportion of the total purchase consideration payable for an acquisition, the amount provided for is the acquisition date fair value of the consideration. The unwinding of the discount element is recognised as a finance cost in the income statement. For business combinations prior to 1 January 2010, all changes in estimated deferred consideration payable on acquisition is adjusted against the carried goodwill. For business combinations after 1 January 2010, changes in estimated deferred consideration payable on acquisition are recognised in the consolidated income statement unless they are measurement period adjustments which are as a result of additional information obtained after the acquisition date about the facts and circumstances existing at the acquisition date, which are adjusted against carried goodwill.

Intangible assets – non oil & gas assets Intangible assets acquired in a business combination are initially measured at cost being their fair values at the date of acquisition and are recognised separately from goodwill where the asset is separable or arises from a contractual or other legal right and its fair value can be measured reliably. After initial recognition, intangible assets are carried at cost less accumulated amortisation and any accumulated impairment losses. Intangible assets with a finite life are amortised over their useful economic life using a straight line method unless a better method reflecting the pattern in which the asset’s future economic benefits are expected to be consumed can be determined. The amortisation charge in respect of intangible assets is included in the selling, general and administration expenses line of the consolidated income statement. The expected useful lives of assets are reviewed on an annual basis. Any change in the useful life or pattern of consumption of the intangible asset is treated as a change in accounting estimate and is accounted for prospectively by changing the amortisation period or method. Intangible assets are tested for impairment whenever there is an indication that the asset may be impaired.

Oil & gas assets Capitalised costs The group’s activities in relation to oil & gas assets are limited to assets in the evaluation, development and production phases.

Oil & gas evaluation and development expenditure is accounted for using the successful efforts method of accounting.

F-154 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

When this is no longer the case, the costs are written-off in the income statement. When such assets are declared part of a commercial development, related costs are transferred to tangible oil & gas assets. All intangible oil & gas assets are assessed for any impairment prior to transfer and any impairment loss is recognised in the consolidated income statement.

Changes in unit-of-production factors Changes in factors which affect unit-of-production calculations are dealt with prospectively, not by immediate adjustment of prior years’ amounts.

Decommissioning Provision for future decommissioning costs is made in full when the group has an obligation to dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. The amount recognised is the present value of the estimated future expenditure. An amount equivalent to the discounted initial provision for decommissioning costs is capitalised and amortised over the life of the underlying asset on a unit-of-production basis over proven and probable reserves. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the oil & gas asset.

The unwinding of the discount applied to future decommissioning provisions is included under finance costs in the income statement.

Available-for-sale financial assets Investments classified as available-for-sale are initially stated at fair value, including acquisition charges associated with the investment.

Impairment of assets (excluding goodwill) At each statement of financial position date, the group reviews the carrying amounts of its tangible and intangible assets to assess whether there is an indication that those assets may be impaired. If any such indication exists, the group makes an estimate of the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows attributable to the asset are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.

F-155 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

Work in progress and billings in excess of cost and estimated earnings Fixed price lump sum engineering, procurement and construction contracts are presented in the statement of financial position as follows: • for each contract, the accumulated cost incurred, as well as the estimated earnings recognised at the contract’s percentage of completion less provision for any anticipated losses, after deducting the progress payments received or receivable from the customers, are shown in current assets in the statement of financial position under ‘Work in progress’ • where the payments received or receivable for any contract exceed the cost and estimated earnings less provision for any anticipated losses, the excess is shown as ‘Billings in excess of cost and estimated earnings’ within current liabilities

Provisions Provisions are recognised when the group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the time value of money is material, provisions are discounted using a

F-156 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised in the consolidated income statement as a finance cost.

Derecognition of financial assets and liabilities Financial assets A financial asset (or, where applicable a part of a financial asset) is derecognised where: • the rights to receive cash flows from the asset have expired; • the group retains the right to receive cash flows from the asset, but has assumed an obligation to pay them in full without material delay to a third party under a ‘pass-through’ arrangement; or • the group has transferred its rights to receive cash flows from the asset and either a) has transferred substantially all the risks and rewards of the asset, or b) has neither transferred nor retained substantially all the risks and rewards of the asset, but has transferred control of the asset

Financial liabilities A financial liability is derecognised when the obligation under the liability is discharged or cancelled or expires.

Pensions and other long-term employment benefits The group has various defined contribution pension schemes in accordance with the local conditions and practices in the countries in which it operates. The amount charged to the consolidated income statement in respect of pension costs reflects the contributions payable in the year. Differences between contributions payable during the year and contributions actually paid are shown as either accrued liabilities or prepaid assets in the statement of financial position.

The group’s other long-term employment benefits are provided in accordance with the labour laws of the countries in which the group operates, further details of which are given in note 27.

Share-based payment transactions Employees (including directors) of the group receive remuneration in the form of share-based payment transactions, whereby employees render services in exchange for shares or rights over shares (‘equity-settled transactions’).

The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the relevant employees become fully entitled to the award (the ‘vesting period’). The cumulative expense recognised for equity-settled transactions at each reporting date until the vesting date reflects the extent to which the vesting period has expired and the group’s best estimate of the number of equity instruments that will ultimately vest. The income statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.

F-157 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

No expense is recognised for awards that do not ultimately vest, except for awards where vesting is conditional upon a market or non-vesting condition, which are treated as vesting irrespective of whether or not the market or non-vesting condition is satisfied, provided that all other performance conditions are satisfied. Equity awards cancelled are treated as vesting immediately on the date of cancellation, and any expense not recognised for the award at that date is recognised in the income statement.

Petrofac Employee Benefit Trust The Petrofac Employee Benefit Trust was established on 7 March 2007 to warehouse ordinary shares purchased to satisfy various new share scheme awards made to the employees of the Company, which will be transferred to the members of the scheme on their respective vesting dates subject to satisfying the performance conditions of each scheme. The trust has been presented as part of both the Company and group financial statements in accordance with SIC 12 ‘Special Purpose Entities’. The cost of shares temporarily held by Petrofac Employee Benefit Trust is reflected as treasury shares and deducted from equity.

The group has entered into various operating leases the payments for which are recognised as an expense in the consolidated income statement on a straight-line basis over the lease terms.

Revenue recognition Revenue is recognised to the extent that it is probable economic benefits will flow to the group and the revenue can be reliably measured. The following specific recognition criteria also apply:

Engineering, procurement and construction services (Engineering & Construction) Revenues from fixed-price lump-sum contracts are recognised on the percentage-of-completion method, based on surveys of work performed once the outcome of a contract can be estimated reliably. In the early stages of contract completion, when the outcome of a contract cannot be estimated reliably, contract revenues are recognised only to the extent of costs incurred that are expected to be recoverable.

Revenues from cost-plus-fee contracts are recognised on the basis of costs incurred during the year plus the fee earned measured by the cost-to-cost method.

Revenues from reimbursable contracts are recognised in the period in which the services are provided based on the agreed contract schedule of rates.

Provision is made for all losses expected to arise on completion of contracts entered into at the statement of financial position date, whether or not work has commenced on these contracts.

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded and the amount of the incentive payments can be measured reliably. Claims and variation orders are only included in revenue when negotiations have reached an advanced stage such that it is probable the claim/variation orders will be accepted and can be measured reliably.

Facilities management, engineering and training services (Offshore Engineering & Operations, Engineering, Training Services and Production Solutions) Revenues from reimbursable contracts are recognised in the period in which the services are provided based on the agreed contract schedule of rates.

F-158 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

Incentive payments are included in revenue when the contract is sufficiently advanced that it is probable that the specified performance standards will be met or exceeded 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.

Oil & gas activities (Energy Developments) Oil & gas revenues comprise the group’s share of sales from the processing or sale of hydrocarbons on an entitlement basis, when the significant risks and rewards of ownership have been passed to the buyer.

Income taxes Income tax expense represents the sum of current income tax and deferred tax.

Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from, or paid to the taxation authorities. Taxable profit differs from profit as reported in the consolidated income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The group’s liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the statement of financial position date.

Deferred income tax is recognised on all temporary differences at the statement of financial position date between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, with the following exceptions: • where the temporary difference arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss; • in respect of taxable temporary differences associated with investments in subsidiaries, associates and joint ventures, where the timing of reversal of the temporary differences can be controlled and it is probable that the temporary differences will not reverse in the foreseeable future; and • deferred income tax assets are recognised only to the extent that it is probable that a taxable profit will be available against which the deductible temporary differences, carried forward tax credits or tax losses can be utilised

F-159 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

Derivative financial instruments and hedging The group uses derivative financial instruments such as forward currency contracts, interest rate collars and swaps and oil price collars and forward contracts to hedge its risks associated with foreign currency, interest rate and oil price fluctuations. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative.

Any gains or losses arising from changes in the fair value of derivatives that do not qualify for hedge accounting are taken to the consolidated income statement.

The group formally designates and documents the relationship between the hedging instrument and the hedged item at the inception of the transaction, as well as its risk management objectives and strategy for undertaking various hedge transactions. The documentation also includes identification of the hedging instrument, the hedged item or transaction, the nature of risk being hedged and how the group will assess the hedging instrument’s effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows attributable to the hedged risk. The group also documents its assessment, both at hedge inception and on an ongoing basis, of whether the derivatives that are used in the hedging transactions are highly effective in offsetting changes in fair values or cash flows of the hedged items.

The treatment of gains and losses arising from revaluing derivatives designated as hedging instruments depends on the nature of the hedging relationship, as follows:

Cash flow hedges For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognised directly in statement of changes in equity, while the ineffective portion is recognised in the income statement. Amounts taken to equity are transferred to the income statement when the hedged transaction affects the consolidated income statement.

If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked, any cumulative gain or loss existing in equity at that time remains in equity and is recognised when the forecast transaction is ultimately recognised in the consolidated income statement. When a forecast transaction is no longer expected to occur, the cumulative gain or loss that was reported in statement of changes in equity is immediately transferred to the consolidated income statement.

Embedded derivatives Contracts are assessed for the existence of embedded derivatives at the date that the group first becomes party to the contract, with reassessment only if there is a change to the contract that significantly modifies the cash flows. Embedded derivatives which are not clearly and closely related to the underlying asset, liability or transaction are separated and accounted for as standalone derivatives.

F-160 Notes to the consolidated financial statements continued For the year ended 31 December 2010

2 Summary of significant accounting policies continued

3 Segment information For management purposes Petrofac is organised into seven main types of business unit activities which have been split into four reportable segments below. Whilst Engineering, Training Services and Production Solutions are three fairly diverse businesses none have ever met the quantitative thresholds set by IFRS 8 ‘Operating Segments’ for determining reportable segments.

The four reportable segments shown below consist of: • Engineering & Construction which provides engineering, procurement and construction project execution services to the onshore oil & gas industry • Offshore Engineering & Operations which provides operations management services to the offshore oil & gas industry • Energy Developments which co-invests with partners in oil & gas production, processing and transportation assets • Engineering, Training Services and Production Solutions activities consist of the provision of early stage engineering services such as conceptual FEED studies, oil & gas related technical competency training and consultancy services and production improvement services under value aligned commercial structures

Management separately monitors the trading results of its seven business units for the purpose of making an assessment of their performance and making decisions about how resources are allocated to them. Each business unit/segment performance is measured based on its profitability which is reflected in a manner consistent with the results shown below. However, certain shareholder services related overheads, group financing and consolidation adjustments are managed at a corporate level and are not allocated to operating segments.

F-161 Notes to the consolidated financial statements continued For the year ended 31 December 2010

3 Segment information continued

The following tables represent revenue and profit information relating to the group’s reporting segments for the year ended 31 December 2010.

Year ended 31 December 2010

Engineering, Training Engineering Offshore Services & Consolidation & Engineering & Production Energy Corporate adjustments & Construction Operations Solutions Developments & others eliminations Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Revenue External sales ...... 3,232,174 710,080 223,748 188,215 — — 4,354,217 Inter-segment sales ...... 21,732 11,821 131,538 — — (165,091) — Total revenue ...... 3,253,906 721,901 355,286 188,215 — (165,091) 4,354,217 Segment results ...... 438,867 24,506 26,590 66,290 (900) (3,362) 551,991 Gain on EnQuest demerger ...... — — — 124,864 — — 124,864 Unallocated corporate costs ..... — — — — (13,405) — (13,405) Profit/(loss) before tax and finance income/(costs) ...... 438,867 24,506 26,590 191,154 (14,305) (3,362) 663,450 Share of loss of associate ...... — — — (131) — — (131) Finance costs ...... — (968) (696) (3,121) (3,659) 3,313 (5,131) Finance income ...... 9,741 209 525 348 2,699 (3,313) 10,209 Profit/(loss) before income tax . . . 448,608 23,747 26,419 188,250 (15,265) (3,362) 668,397 Income tax (expense)/income .... (75,550) (6,519) 1,144 (31,895) 2,275 — (110,545) Non-controlling interests ...... (35) — — — — — (35) Profit/(loss) for the year attributable to Petrofac Limited shareholders ...... 373,023 17,228 27,563 156,355 (12,990) (3,362) 557,817 Other segment information Capital expenditures: Property, plant and equipment . . . 62,088 2,785 6,857 41,112 4,575 (1,178) 116,239 Intangible oil & gas assets ...... — — — 15,644 — — 15,644 Charges: Depreciation ...... 34,340 2,238 7,206 49,816 367 (575) 93,392 Amortisation ...... 1,044 597 870 — — — 2,511 Other long-term employment benefits ...... 10,435 613 1,581 54 87 — 12,770 Share-based payments ...... 7,693 1,167 1,896 1,121 2,907 — 14,784

F-162 Notes to the consolidated financial statements continued For the year ended 31 December 2010

3 Segment information continued

Year ended 31 December 2009 (restated)

Engineering, Restated Offshore Training Consolidation Engineering Engineering Services & adjustments & & Production Energy Corporate & Restated Construction Operations Solutions Developments & others eliminations Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Revenue External sales ...... 2,508,951 616,542 281,225 248,708 — — 3,655,426 Inter-segment sales ...... — 10,178 68,431 — — (78,609) — Total revenue ...... 2,508,951 626,720 349,656 248,708 — (78,609) 3,655,426 Segment results ...... 312,374 17,830 34,483 77,395 (1,615) (326) 440,141 Unallocated corporate costs ...... — — — — (8,181) — (8,181) Profit/(loss) before tax and finance income/(costs) ...... 312,374 17,830 34,483 77,395 (9,796) (326) 431,960 Finance costs ...... — (258) (1,582) (10,702) (5,705) 12,665 (5,582) Finance income ...... 14,087 94 313 64 10,049 (12,665) 11,942 Profit/(loss) before income tax ...... 326,461 17,666 33,214 66,757 (5,452) (326) 438,320 Income tax (expense)/income ...... (61,328) (4,853) (672) (20,566) 3,095 (191) (84,515) Minority interests ...... (14) — (188) — — — (202) Profit/(loss) for the year attributable to Petrofac Limited shareholders ...... 265,119 12,813 32,354 46,191 (2,357) (517) 353,603 Other segment information Capital expenditures: Property, plant and equipment ...... 51,821 3,400 6,682 309,824 4,686 (1,014) 375,399 Intangible oil & gas assets ...... — — — 29,230 — — 29,230 Charges: Depreciation ...... 24,525 1,887 7,482 78,677 251 (918) 111,904 Amortisation ...... 415 — 668 — — — 1,083 Impairment ...... — — — 4,793 — — 4,793 Other long-term employment benefits ...... 7,779 833 1,736 52 38 — 10,438 Share-based payments ...... 6,213 1,263 2,258 1,337 2,192 — 13,263

F-163 Notes to the consolidated financial statements continued For the year ended 31 December 2010

3 Segment information continued

Year ended 31 December 2010

United Arab United Saudi Other Algeria Emirates Kingdom Kuwait Oman Syria Arabia countries Consolidated US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Revenues from external customers ...... 1,037,966 798,328 753,842 360,624 350,313 277,196 235,936 540,012 4,354,217

United United Arab Other Kingdom Emirates Tunisia Algeria Malaysia Indonesia countries Consolidated US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Non-current assets: Property, plant and equipment ...... 54,326 94,292 52,031 30,737 14,836 1,555 39,381 287,158 Intangible oil & gas assets . . — — — — 69,532 — — 69,532 Other intangible assets ..... 9,365 — — — — 6,940 — 16,305 Goodwill ...... 90,093 15,240 — — — — 499 105,832

Year ended 31 December 2009

United United Arab Other Kingdom Emirates Syria Algeria Oman Kuwait Kazakhstan countries Consolidated US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Revenues from external customers ...... 705,281 695,118 530,269 492,378 380,601 203,577 184,305 463,897 3,655,426

United United Arab Other Kingdom Tunisia Emirates Algeria Malaysia countries Consolidated US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Non-current assets: Property, plant and equipment ...... 447,591 57,078 74,093 55,229 25,279 18,726 677,996 Intangible oil & gas assets ...... — — — — 53,888 — 53,888 Other intangible assets ...... 11,654 — — — — 7,565 19,219 Goodwill ...... 85,155 — 12,099 — — 668 97,922

Revenues disclosed in the above tables are based on where the project is located. Revenue from two customers amounted to S$1,422,410,000 (2009: US$801,723,000) in the Engineering & Construction segment.

4 Revenues and expenses a. Revenue

2010 2009 US$’000 US$’000 Rendering of services ...... 4,202,371 3,446,037 Sale of crude oil & gas ...... 146,075 202,770 Sale of processed hydrocarbons ...... 5,771 6,619 4,354,217 3,655,426

Included in revenues from rendering of services are Offshore Engineering & Operations, Engineering, Training Services and Production Solutions revenues of a ‘pass-through’ nature with zero or low margins amounting to US$227,974,000 (2009: US$230,262,000).

F-164 Notes to the consolidated financial statements continued For the year ended 31 December 2010

4 Revenues and expenses continued b. Cost of sales Included in cost of sales for the year ended 31 December 2010 is US$154,000 (2009: US$908,000 gain) gain on disposal of property, plant and equipment used to undertake various engineering and construction contracts. In addition depreciation charged on property, plant and equipment of US$85,186,000 during 2010 (2009: US$104,997,000) is included in cost of sales (note 9).

Also included in cost of sales are forward points and ineffective portions on derivatives designated as cash flow hedges and loss on maturity of undesignated derivatives of US$3,409,000 (2009: US$19,508,000 gain). These amounts are an economic hedge but do not meet the criteria within IAS39 and are most appropriately recorded in cost of sales. c. Selling, general and administration expenses 2010 2009 US$’000 US$’000 Staff costs ...... 126,475 94,583 Depreciation ...... 8,206 6,907 Amortisation (note 13) ...... 2,511 1,083 Impairment ...... — 4,793 Other operating expenses ...... 84,257 78,927 221,449 186,293

Other operating expenses consist mainly of office, travel, legal and professional and contracting staff costs. d. Staff costs 2010 2009 US$’000 US$’000 Total staff costs: Wages and salaries ...... 828,439 708,684 Social security costs ...... 31,809 27,877 Defined contribution pension costs ...... 12,621 11,155 Other long-term employee benefit costs (note 27) ...... 12,770 10,438 Expense of share-based payments (note 24) ...... 14,784 13,263 900,423 771,417

Of the US$900,423,000 (2009: US$771,417,000) of staff costs shown above, US$773,948,000 (2009: US$676,834,000) are included in cost of sales, with the remainder in selling, general and administration expenses.

The average number of persons employed by the group during the year was 12,807 (2009: 11,628). e. Auditors’ remuneration The group paid the following amounts to its auditors in respect of the audit of the financial statements and for other services provided to the group:

2010 2009 US$’000 US$’000 Audit of the group financial statements ...... 1,209 1,369 Other fees to auditors: Local statutory audits of subsidiaries ...... 812 546 Tax services ...... 520 178 All other services ...... 93 15 2,634 2,108

F-165 Notes to the consolidated financial statements continued For the year ended 31 December 2010

4 Revenues and expenses continued f. Other income

2010 2009 US$’000 US$’000 Foreign exchange gains ...... 720 2,342 Gain on sale of property, plant and equipment ...... 8 — Gain on sale of intangible assets ...... 2,338 — Other income ...... 1,947 1,733 5,013 4,075 g. Other expenses

2010 2009 US$’000 US$’000 Foreign exchange losses ...... 3,452 2,675 Loss on sale of property, plant and equipment ...... 477 124 Other expenses ...... 124 199 4,053 2,998

5 Finance (costs)/income 2010 2009 US$’000 US$’000 Interest payable: Long-term borrowings ...... (2,908) (3,171) Other interest, including short-term loans and overdrafts ...... (581) (310) Unwinding of discount on deferred consideration and decommissioning provisions ...... (1,642) (2,101) Total finance cost ...... (5,131) (5,582)

Interest receivable: Bank interest receivable ...... 9,945 11,487 Other interest receivable ...... 264 455 Total finance income ...... 10,209 11,942

6 Income tax a. Tax on ordinary activities The major components of income tax expense are as follows:

2010 2009 US$’000 US$’000 Current income tax Current income tax charge ...... 115,199 100,985 Adjustments in respect of current income tax of previous years ...... (2,843) (31,448) Deferred income tax Relating to origination and reversal of temporary differences ...... 907 5,570 Adjustments in respect of deferred income tax of previous years ...... (2,718) 9,408 Income tax expense reported in the income statement ...... 110,545 84,515

F-166 Notes to the consolidated financial statements continued For the year ended 31 December 2010

6 Income tax continued b. Reconciliation of total tax charge A reconciliation between the income tax expense and the product of accounting profit multiplied by the Company’s domestic tax rate is as follows: 2010 2009 US$’000 US$’000 Accounting profit before tax (including gain on EnQuest demerger) ...... 668,397 438,320 At Jersey’s domestic income tax rate of 0% (2009: 0%) ...... — — Expected tax charge in higher rate jurisdictions ...... 116,199 107,320 Expenditure not allowable for income tax purposes ...... 1,073 14,706 Income not taxable ...... — (396) Adjustments in respect of previous years ...... (5,561) (22,040) Tax effect of utilisation of tax losses not previously recognised ...... (568) (252) Unrecognised tax losses ...... 1,634 618 Other permanent differences ...... (2,157) (15,441) Effect of change in tax rates ...... (75) — At the effective income tax rate of 16.5% (2009: 19.3%) ...... 110,545 84,515

The group’s effective tax rate for the year ended 31 December 2010, including the US$124,864,000 gain on the demerger of Energy Development’s UKCS business is 16.5% and excluding this gain, the effective tax rate is 20.3% (2009: 19.3%).

On 5 April 2010, the group completed the demerger of its UKCS business to EnQuest PLC, an independent company which is listed on the London and Stockholm stock exchanges. No chargeable gain arose on the transaction for UK corporate tax purposes. This decreased the group’s effective tax rate for the period.

Excluding the gain from the demerger, there has been a small increase in the group’s effective tax rate. Factors contributing to this increase compared to 2009 include ring fence expenditure supplement no longer being available for claim following the demerger of Petrofac Energy Developments Limited, no additional adjustments being made in respect of the applicability of the lower tax rate to the group’s project in Oman, material changes in jurisdictions in which profits are expected to be earned by the Engineering & Construction reporting segment and due to recent acquisitions. There has also been an increase in reportable profit within taxable jurisdictions. In June 2010, the UK Government announced its intention to propose to Parliament to reduce the UK corporation tax rate from 28% to 24% over the course of four years. From 1 April 2011 the UK corporate rate is 27% and will impact the reversal of the temporary difference from this date onwards, reducing the UK tax assets and liabilities. This UK tax rate change has been substantively enacted at the statement of financial position date. c. Deferred income tax Deferred income tax relates to the following: Consolidated Statement Consolidated Income of Financial Position Statement 2010 2009 2010 2009 US$’000 US$’000 US$’000 US$’000 Deferred income tax liabilities Fair value adjustment on acquisitions ...... 1,412 2,599 (597) (139) Accelerated depreciation ...... 36,580 27,515 14,630 15,472 Other temporary differences ...... 10,094 12,078 (4,336) (1,441) Gross deferred income tax liabilities ...... 48,086 42,192 Deferred income tax assets Losses available for offset ...... 2,259 18,413 (14,135) (11,130) Decelerated depreciation for tax purposes ...... 2,404 7,596 327 9,409 Share scheme ...... 15,721 18,636 (230) (1,142) Other temporary differences ...... 5,917 5,081 2,530 3,949 Gross deferred income tax assets ...... 26,301 49,726 Deferred income tax (credit)/charge ...... (1,811) 14,978

F-167 Notes to the consolidated financial statements continued For the year ended 31 December 2010

6 Income tax continued d. Unrecognised tax losses and tax credits Deferred income tax assets are recognised for tax loss carry-forwards and tax credits to the extent that the realisation of the related tax benefit through future taxable profits is probable. The group did not recognise deferred income tax assets of US$18,366,000 (2009: US$15,452,000). 2010 2009 US$’000 US$’000 Expiration dates for tax losses No earlier than 2022 ...... 9,466 11,451 No expiration date ...... 6,384 3,360 15,850 14,811 Tax credits (no expiration date) ...... 2,516 641 18,366 15,452

Diluted earnings per share amounts are calculated by dividing the net profit attributable to ordinary shareholders, after adjusting for any dilutive effect, by the weighted average number of ordinary shares outstanding during the year, adjusted for the effects of ordinary shares granted under the employee share award schemes which are held in trust.

The following reflects the income and share data used in calculating basic and diluted earnings per share: 2010 2009 US$’000 US$’000 Net profit attributable to ordinary shareholders for basic and diluted earnings per share excluding gain on EnQuest demerger ...... 432,953 353,603 Net profit attributable to ordinary shareholders for basic and diluted earnings per share including gain on EnQuest demerger ...... 557,817 353,603

2010 2009 Number Number ’000 ’000 Weighted average number of ordinary shares for basic earnings per share ...... 338,867 337,473 Effect of diluted potential ordinary shares granted under share-based payment schemes .... 4,493 5,187 Adjusted weighted average number of ordinary shares for diluted earnings per share ...... 343,360 342,660

8 Dividends paid and proposed 2010 2009 US$’000 US$’000 Declared and paid during the year Equity dividends on ordinary shares: Final dividend for 2008: 17.90 cents per share ...... — 60,332 Interim dividend 2009: 10.70 cents per share ...... — 36,197 Final dividend for 2009: 25.10 cents per share ...... 85,291 — Interim dividend 2010: 13.80 cents per share ...... 46,757 — 132,048 96,529

2010 2009 US$’000 US$’000 Proposed for approval at AGM (not recognised as a liability as at 31 December) Equity dividends on ordinary shares Final dividend for 2010: 30.00 cents per share (2009: 25.10 cents per share) ...... 103,715 86,729

F-168 Notes to the consolidated financial statements continued For the year ended 31 December 2010

9 Property, plant and equipment

Land, buildings Office and furniture Assets Oil & gas Oil & gas leasehold Plant and and under assets facilities improvements equipment Vehicles equipment construction Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Cost At 1 January 2009 ...... 279,103 125,371 83,088 22,235 6,574 69,047 — 585,418 Additions ...... 276,798 32,612 32,632 4,273 4,907 17,663 6,514 375,399 Disposals ...... — — (1,474) (4,631) (789) (3,366) — (10,260) Exchange difference ...... — — 1,296 1,103 204 3,745 165 6,513 At 1 January 2010 ...... 555,901 157,983 115,542 22,980 10,896 87,089 6,679 957,070 Additions ...... 32,252 7,602 44,114 1,445 4,755 19,238 6,833 116,239 Acquisition of subsidiaries .... — — — 2,081 46 43 — 2,170 Disposals ...... (470,447) — (1,847) (2,344) (854) (17,268) — (492,760) Transfers ...... — — 881 4 — (885) — — Exchange difference ...... — — (462) (712) (158) (809) (132) (2,273) At 31 December 2010 ...... 117,706 165,585 158,228 23,454 14,685 87,408 13,380 580,446

Depreciation At 1 January 2009 ...... (16,187) (87,026) (7,983) (16,512) (4,235) (40,411) — (172,354) Charge for the year ...... (60,984) (15,254) (14,998) (3,571) (2,254) (14,843) — (111,904) Disposals ...... — — 1,330 4,516 740 3,150 — 9,736 Exchange difference ...... — — (379) (1,051) (37) (3,085) — (4,552) At 1 January 2010 ...... (77,171)(102,280) (22,030) (16,618) (5,786) (55,189) — (279,074) Charge for the year ...... (32,204) (15,993) (23,981) (2,734) (3,462) (15,018) — (93,392) Disposals ...... 59,592 — 1,400 538 769 16,072 — 78,371 Transfers ...... — — (83) — — 83 — — Exchange difference ...... — — 71 327 28 381 — 807 At 31 December 2010 ...... (49,783)(118,273) (44,623) (18,487) (8,451) (53,671) — (293,288) Net carrying amount: At 31 December 2010 ...... 67,923 47,312 113,605 4,967 6,234 33,737 13,380 287,158 At 31 December 2009 ...... 478,730 55,703 93,512 6,362 5,110 31,900 6,679 677,996

No interest has been capitalised within oil & gas facilities during the year (2009: nil) and the accumulated capitalised interest, net of depreciation at 31 December 2010, was US$432,000 (2009: US$931,000).

Additions to oil & gas assets in 2009 mainly comprise development expenses capitalised on the group’s interest in the Don area assets of US$274,114,000. During the year, the Don assets were demerged and as a result oil & gas assets with a net book value of US$410,855,000 were disposed of (note 11).

Included in oil & gas assets are US$2,196,000 (2009: US$50,726,000) of capitalised decommissioning costs net of depreciation provided on the PM304 asset in Malaysia and the Chergui asset in Tunisia. The decrease in the 31 December 2010 oil & gas asset’s balance is due to the demerger of the Don area assets in the United Kingdom (note 11).

Of the total charge for depreciation in the income statement, US$85,186,000 (2009: US$104,997,000) is included in cost of sales and US$8,206,000 (2009: US$6,907,000) in selling, general and administration expenses.

Assets under construction comprises of expenditures incurred in relation to the group ERP project.

F-169 Notes to the consolidated financial statements continued For the year ended 31 December 2010

10 Business combinations Scotvalve Services Limited On 14 January 2010, the group acquired a 100% interest in the share capital of Scotvalve Services Limited (Scotvalve), a United Kingdom based company, involved in the servicing and repair of oilfield pressure control equipment. The Scotvalve acquisition will enhance the group’s mechanical services offering and expand its geographical footprint. The consideration for the acquisition was Sterling 4,630,000 (equivalent US$7,512,000) comprising of Sterling 2,801,000 (equivalent US$4,545,000) as an initial cash payment, Sterling 150,000 (equivalent US$243,000) to be settled in cash during the year and the balance being the discounted value of deferred consideration amounting to Sterling 1,679,000 (equivalent US$2,724,000) payable based on the estimated future profitability of Scotvalve. The range of deferred consideration payable is from zero to a maximum of Sterling 2,000,000 (equivalent US$3,122,000) over a three year period.

The fair values of the identifiable assets and liabilities of Scotvalve on completion of the acquisition are analysed below: Recognised on Carrying acquisition value US$’000 US$’000 Property, plant and equipment ...... 1,891 1,978 Investments in associates (note 14) ...... 777 777 Intangible assets (note 13) ...... 1,107 — Trade and other receivables ...... 2,606 2,606 Cash and short-term deposits ...... 410 410 Total assets ...... 6,791 5,771 Less: Deferred tax liability ...... (325) (16) Income tax liability ...... (279) (279) Trade and other payables ...... (1,220) (1,220) Total liabilities ...... (1,824) (1,515) Fair value of net assets acquired ...... 4,967 4,256 Goodwill arising on acquisition ...... 2,545 Consideration at acquisition ...... 7,512

US$’000 Cash outflow on acquisition: Cash acquired with subsidiary ...... 410 Cash paid on acquisition ...... (4,545) Net cash outflow on the acquisition of subsidiary ...... (4,135)

Intangible assets recognised on acquisition comprise equipment manufacturer warranty repair licenses which are being amortised over their remaining economic useful lives of five years on a straight-line basis.

The residual goodwill above comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the group.

From the date of acquisition, Scotvalve has contributed revenues of US$6,903,000 and net income of US$1,020,000 to the net profit of the group. If the above combination had taken place at the beginning of the year, net profit of Scotvalve would have been US$1,020,000 and revenue would have been US$6,903,000.

The transaction costs of Sterling 102,000 (equivalent US$154,000) relating to the acquisition have been expensed in the year and are included within selling, general and administration and are included as cash flows from operating activities in the consolidated cash flow statement.

The deferred consideration payable was re-assessed at year end in light of latest financial projections for the business and the current carried amount was reduced by Sterling 135,000 (equivalent US$208,000) with a corresponding increase in other income within the consolidated income statement.

F-170 Notes to the consolidated financial statements continued For the year ended 31 December 2010

10 Business combinations continued

Stephen Gillespie Consultants Limited On 1 April 2010, the group acquired a 100% interest in the share capital of Stephen Gillespie Consultants Limited (SGC), a United Kingdom based provider of software consultancy to flow metering control system manufacturers for a consideration of Sterling 4,523,000 (equivalent US$6,853,000) comprising of Sterling 3,178,000 (equivalent US$4,815,000) paid upfront in cash and the balance being the discounted value of deferred consideration amounting to Sterling 1,345,000 (equivalent US$2,038,000) payable based on the estimated future revenue of the company. This acquisition will enhance the group’s existing metering service offering and also its ability to provide turnkey metering solutions to both brownfield and greenfield international oil & gas projects. The range of deferred consideration payable is from Sterling 600,000 (equivalent US$937,000) to a maximum of Sterling 1,200,000 (equivalent US$1,873,000) based on future revenue of SGC over a two year period. The fair values of the identifiable assets and liabilities of SGC on completion of the acquisition are analysed below: Recognised on Carrying acquisition value US$’000 US$’000 Property, plant and equipment ...... 61 61 Intangible assets (note 13) ...... 2,065 — Trade and other receivables ...... 1,424 1,424 Cash and short-term deposits ...... 1,920 1,920 Total assets ...... 5,470 3,405 Less: Deferred tax liability ...... (579) — Income tax liability ...... (383) (383) Trade and other payables ...... (1,126) (1,254) Total liabilities ...... (2,088) (1,637) Fair value of net assets acquired ...... 3,382 1,768 Goodwill arising on acquisition ...... 3,471 Consideration at acquisition ...... 6,853

US$’000 Cash outflow on acquisition: Cash acquired with subsidiary ...... 1,920 Cash paid on acquisition ...... (4,815) Net cash outflow on the acquisition of subsidiary ...... (2,895)

Intangible assets recognised on acquisition comprise of software related to metering technology which is being amortised over its remaining economic useful lives of five years on a straight-line basis. The residual goodwill above comprises the fair value of expected future synergies and business opportunities arising from the integration of the business in to the group. From the date of acquisition, SGC has contributed revenues of US$6,549,000 and net income of US$165,000 to the net profit of the group. If the above combination had taken place at the beginning of the year, net profit of SGC would have been US$205,000 and revenue would have been US$7,412,000. The transaction costs of Sterling 65,000 (equivalent US$99,000) relating to the acquisition have been expensed in the year and are included within selling, general and administration and are included as cash flows from operating activities in the consolidated cash flow statement. The deferred consideration payable was re-assessed at year end in light of latest financial projections for the business and the current carried amount was reduced by Sterling 188,000 (equivalent US$293,000) with a corresponding increase in other income within the consolidated income statement.

F-171 Notes to the consolidated financial statements continued For the year ended 31 December 2010

10 Business combinations continued

CO2DeepStore Limited

On 27 April 2010, the group acquired a 100% interest in the share capital of CO2DeepStore Limited (CO2DeepStore), a United Kingdom based company focused on the CO2 geological storage sector of the carbon capture and storage market for a cash consideration of Sterling 220,000 (equivalent US$340,000). This acquisition represents the group’s first step into the strategically important emerging low carbon energy sector.

The fair values of the identifiable assets and liabilities of CO2DeepStore on completion of the acquisition are analysed below:

Recognised on Carrying acquisition value US$’000 US$’000 Property, plant and equipment ...... 3 3 Trade and other receivables ...... 134 134 Cash and short-term deposits ...... 263 263 Total assets ...... 400 400

Less: Income tax liability ...... (31) (31) Trade and other payables ...... (29) (29) Total liabilities ...... (60) (60)

Fair value of net assets acquired ...... 340 340 Goodwill arising on acquisition ...... — Consideration at acquisition ...... 340

US$’000 Cash outflow on acquisition: Cash acquired with subsidiary ...... 263 Cash paid on acquisition ...... (340) Net cash outflow on the acquisition of subsidiary ...... (77)

From the date of acquisition, CO2DeepStore has contributed revenues of US$88,000 and a net loss of US$823,000 to the net profit of the group. If the above combination had taken place at the beginning of the year, net profit of CO2DeepStore would have been US$573,000 and revenue would have been US$905,000.

The transaction costs of Sterling 17,000 (equivalent US$26,000) relating to the acquisition have been expensed in the year and are included within selling, general and administration and are included as cash flows from operating activities in the consolidated cash flow statement.

Under the terms of the acquisition agreement, costs of up to Sterling 200,000 (equivalent US$312,000) will be payable to the former owners of CO2DeepStore three years from the date of completion based on the estimated future profitability of the company and will be recognised as an expense in the income statement over this period. The charge for the current year is Sterling 44,000 (equivalent US$68,000).

TNEI Services Limited On 14 June 2010, the group acquired a 100% interest in the share capital of TNEI Services Limited (TNEI) through the acquisition of its holding company New Energy Industries Limited for a cash consideration of Sterling 6,123,000 (equivalent US$8,913,000). TNEI provides services in the areas of power transmission and distribution, planning and environmental consent and energy management. The acquisition of TNEI further broadens the group’s technical consulting services offering in the rapidly developing power and renewable energy markets.

F-172 Notes to the consolidated financial statements continued For the year ended 31 December 2010

10 Business combinations continued

The fair values of the identifiable assets and liabilities of TNEI on completion of the acquisition are analysed below:

Recognised on Carrying acquisition value US$’000 US$’000 Property, plant and equipment ...... 215 215 Acquired goodwill ...... 881 881 Trade and other receivables ...... 1,779 1,779 Cash and short-term deposits ...... 910 910 Total assets ...... 3,785 3,785

Less: Trade and other payables ...... (1,198) (1,198) Total liabilities ...... (1,198) (1,198)

Fair value of net assets acquired ...... 2,587 2,587 Goodwill arising on acquisition ...... 6,326 Consideration at acquisition ...... 8,913

US$’000 Cash outflow on acquisition: Cash acquired with subsidiary ...... 910 Cash paid on acquisition ...... (8,913) Net cash outflow on the acquisition of subsidiary ...... (8,003)

The residual goodwill above comprises the fair value of expected future synergies and business opportunities arising from the integration of the business into the group.

From the date of acquisition, TNEI has contributed revenue of US$3,898,000 and a net loss of US$5,000 to the group. If the above combination had taken place at the beginning of the year, net profit of TNEI would have been US$301,000 and revenue would have been US$6,296,000.

The transaction costs of Sterling 38,000 (equivalent US$58,000) relating to the acquisition have been expensed in the year and are included within selling, general and administration and are included as cash flows from operating activities in the consolidated cash flow statement.

Under the terms of the acquisition agreement, Sterling 1,538,000 (equivalent US$2,370,000) will be payable 50% in Petrofac shares and 50% in cash to the former owners of TNEI who remain as employees of the Petrofac group in three equal tranches over three years from the date of completion which will be recognised as an expense in the income statement on a straight line basis over the three years. The charge for the current year is Sterling 278,000 (equivalent US$428,000).

F-173 Notes to the consolidated financial statements continued For the year ended 31 December 2010

11 Gain on EnQuest demerger On 5 April 2010, the group’s interests in the Don area oil assets were demerged via a transfer of three of its subsidiaries, Petrofac Energy Developments Limited (PEDL), Petrofac Energy Developments Oceania Limited (PEDOL) and PEDL Limited (PEDLL) to EnQuest PLC for a deemed consideration for accounting purposes of US$553,300,000 which was settled by the issue of EnQuest PLC shares directly to Petrofac Limited shareholders*. The gain on the demerger transaction has been computed as follows:

US$’000 Fair value of consideration ...... 553,300 Less: Property, plant and equipment ...... (410,855) Deferred tax asset ...... (27,394) Inventories ...... (5,578) Trade and other receivables ...... (107,039) Cash and bank ...... (16,147) Total book value of assets transferred ...... (567,013) Provision for decommissioning ...... 55,967 Trade and other payables ...... 130,348 Translation reserve ...... (3,308) Total book value of liabilities transferred ...... 183,007 Net assets transferred ...... (384,006) Transaction costs ...... (1,636) Release of foreign currency translation reserve ...... (45,818) Allocated goodwill written off (note 12) ...... (1,146) Other consolidation adjustments ...... 4,170 Gain on demerger ...... 124,864

* In order to effect the demerger of the PEDL sub group to EnQuest, the existing issued ordinary share capital of Petrofac Limited was subdivided and converted into new ordinary Petrofac shares with a nominal value of US$0.02 each and Petrofac B shares of US$0.005 each and subsequent to this share split the B shares were purchased and cancelled in exchange for an allotment and issue of EnQuest ordinary shares directly to holders of Petrofac B shares.

As a result of this capital re-organisation and purchase of Petrofac B shares US$1,728,000 of Petrofac issued ordinary share capital was extinguished and transferred to retained earnings and the non-cash distribution to Petrofac shareholders for accounting purposes of US$553,300,000 was made via the utilisation of the existing share premium account balance of US$71,172,000 with the remaining amount of US$482,128,000 being transferred out of retained earnings. In addition US$8,803,000 of proceeds generated by the Petrofac Employee Benefit Trust selling its holding of EnQuest shares arising from the demerger have been credited to retained earnings leaving a net impact on retained earnings of US$473,325,000.

12 Goodwill A summary of the movements in goodwill is presented below:

2010 2009 US$’000 US$’000 At 1 January ...... 97,922 97,534 Acquisitions during the year (note 10) ...... 13,223 — Reassessment of deferred consideration payable ...... (1,313) (8,992) Write off on EnQuest demerger (note 11) ...... (1,146) — Exchange difference ...... (2,854) 9,380 At 31 December ...... 105,832 97,922

F-174 Notes to the consolidated financial statements continued For the year ended 31 December 2010

12 Goodwill continued

Reassessment of deferred consideration payable mainly comprises of the reduction in deferred consideration payable on Caltec Limited of US$4,285,000 (2009: US$2,929,000 decrease) and an increase in deferred consideration payable on SPD Group Limited of US$3,141,000 (2009: US$4,351,000 decrease).

Goodwill acquired through business combinations has been allocated to five groups of cash-generating units, which are operating segments, for impairment testing as follows: • Offshore Engineering & Operations • Engineering Services • Production Solutions • Training Services • Energy Developments

These represent the lowest level within the group at which the goodwill is monitored for internal management purposes.

Offshore Engineering & Operations, Engineering Services, Production Solutions and Training cash- generating units The recoverable amounts for the Offshore Engineering & Operations, Engineering Services, Production Solutions and Training units have been determined based on value in use calculations, using discounted pre-tax cash flow projections. Management has adopted a ten-year projection period to assess each unit’s value in use as it is confident based on past experience of the accuracy of long-term cash flow forecasts that these projections are reliable. The cash flow projections are based on financial budgets approved by senior management covering a five year period, extrapolated for a further five years at a growth rate of 5% for Offshore Engineering & Operations, Engineering Services and Training cash-generating units and 2.5% per annum for Production Solutions cash-generating unit since it includes newly acquired businesses where there is less historic track record of achieving financial projections.

Energy Developments cash-generating unit The recoverable amount of the Energy Developments unit is also determined on a value in use calculation using discounted pre-tax cash flow projections based on financial budgets and economic assumptions for the unit approved by senior management and covering a five-year period, as referred to in IAS 36.

Carrying amount of goodwill allocated to each group of cash-generating units

2010 2009 US$’000 US$’000 Offshore Engineering & Operations unit ...... 27,992 22,975 Engineering Services ...... 7,728 — Production Solutions unit ...... 49,739 52,496 Training Services unit ...... 19,302 20,234 Energy Developments unit ...... 1,071 2,217 105,832 97,922

Key assumptions used in value in use calculations The calculation of value in use for the Offshore Engineering & Operations, Engineering Services, Production Solutions and Training Services units is most sensitive to the following assumptions:

Market share: the assumption relating to market share for the Offshore Engineering & Operations unit is based on the unit re-securing those existing customer contracts in the UK which are due to expire during the projection period; for the Training Services unit, the key assumptions relate to management’s assessment of maintaining the unit’s market share in the UK and developing further the business in international markets.

F-175 Notes to the consolidated financial statements continued For the year ended 31 December 2010

12 Goodwill continued

Growth rate: estimates are based on management’s assessment of market share having regard to macro-economic factors and the growth rates experienced in the recent past by each unit. A growth rate of 5% per annum has been applied for Offshore Engineering & Operations, Engineering Services and Training Services cash-generating units for the remaining five years of the ten-year projection period and 2.5% per annum for Production Solutions cash-generating unit since it includes newly acquired businesses where there is less historic track record of achieving financial projections.

Net profit margins: estimates are based on management’s assumption of achieving a level of performance at least in line with the recent past performance of each of the units.

Discount rate: management has used a pre-tax discount rate of 14.6% per annum for each of Offshore Engineering & Operations (2009: 14.5%), Engineering Services (2009: n/a) Production Solutions (2009: 14.5%) and Training (2009: 14.5%) cash-generating units which are derived from the estimated weighted average cost of capital of the group. This discount rate has been calculated using an estimated risk free rate of return adjusted for the group’s estimated equity market risk premium and the group’s cost of debt.

The calculation of value in use for the Energy Developments unit is most sensitive to the following assumptions:

Discount rate: management has used an estimate of the pre-tax weighted average cost of capital of the group plus a risk premium to reflect the particular risk characteristics of each individual asset. The discount rate used for 2010 was 13.4% for each asset (2009: 10.5%).

Oil & gas prices: management has used an oil price assumption of US$75.00 (2009: US$70.00) per barrel and a gas price of US$8.73 (2009: US$8.30) per mcf for the impairment testing of its individual oil & gas investments.

Reserve volumes and production profiles: management has used its internally developed economic models of reserves and production as a basis of calculating value in use.

Sensitivity to changes in assumptions Other than the assumed success of the Ticleni contract in Production Solutions with regard to the assessment of value in use of the cash generating units, management believes that no reasonably possible change in any of the above key assumptions would cause the carrying value of the relevant unit to exceed its recoverable amount, after giving due consideration to the macro-economic outlook for the oil & gas industry and the commercial arrangements with customers underpinning the cash flow forecasts for each of the units.

F-176 Notes to the consolidated financial statements continued For the year ended 31 December 2010

13 Intangible assets

2010 2009 US$’000 US$’000 Intangible oil & gas assets Cost: At 1 January ...... 53,888 43,137 Additions ...... 15,644 29,230 Disposal ...... — (18,479) At 31 December ...... 69,532 53,888 Accumulated impairment: At 1 January ...... — (13,686) Impairment ...... — (4,793) Disposal ...... — 18,479 At 31 December ...... — — Net book value of intangible oil & gas assets at 31 December ...... 69,532 53,888

Other intangible assets Cost: At 1 January ...... 25,476 13,892 Additions on acquisition (note 10) ...... 3,172 — Additions ...... 153 10,375 Disposal ...... (4,220) — Exchange difference ...... (43) 1,209 At 31 December ...... 24,538 25,476 Accumulated amortisation: At 1 January ...... (6,257) (4,990) Amortisation ...... (2,511) (1,083) Disposal ...... 540 — Exchange difference ...... (5) (184) At 31 December ...... (8,233) (6,257) Net book value of other intangible assets at 31 December ...... 16,305 19,219 Total intangible assets ...... 85,837 73,107

Intangible oil & gas assets Oil & gas asset (part of the Energy Development segment) additions above comprise of US$15,644,000 (2009: US$29,230,000) of capitalised expenditure on the group’s assets in Malaysia.

There were investing cash outflows relating to capitalised intangible oil & gas assets of US$15,644,000 (2009: US$29,230,000) in the current period arising from pre-development activities.

Other intangible assets Other intangible assets comprising customer contracts, proprietary software, LNG intellectual property and patent technology are being amortised over their remaining estimated economic useful life of three, six, eight and ten years respectively on a straight-line basis and the related amortisation charges included in selling, general and administrative expenses (note 4c). During the year, proprietary software was disposed of with a resulting gain disclosed in other income (note 4f).

F-177 Notes to the consolidated financial statements continued For the year ended 31 December 2010

14 Investment in associates

2010 2009 US$’000 US$’000 Investment in Gateway Storage Company Limited ...... 15,795 — Associates acquired through acquisition of Scotvalve (note 10) ...... 777 — Share of associate loss ...... (131) — Exchange difference ...... (92) — 16,349 —

Gateway Storage Company Limited On 6 December 2010, the group acquired a 20% equity interest in Gateway Storage Company Limited (Gateway), an unlisted entity, to progress and develop the Gateway Gas Storage project in the East Irish Sea. The initial cost of the investment was Sterling 5,000,000 (equivalent US$7,795,000) together with, transaction costs of US$664,000 and contracted value of free services to be provided by the group of Sterling 500,000 (equivalent US$780,000). Additional contingent payments may become payable under the terms of the investment, subject to key project development milestones being achieved, including the outcome of further successful equity sales. Deferred consideration of Sterling 4,160,000 (equivalent US$6,556,000) has been estimated as payable using a discounted storage project cash flow model assuming certain project scenarios to which estimated probabilities were assigned by management. The deferred consideration in no event will exceed an additional amount of Sterling 28,000,000 (equivalent US$43,705,000). The share of the associate’s statement of financial position is as follows:

2010 US$’000 Non-current assets ...... 123 Current assets ...... 3,050 Current liabilities ...... (795) Equity ...... 2,378 Transaction costs incurred ...... 664 Fair value of free services to be provided ...... 780 Deferred consideration payable ...... 6,556 Exchange on deferred consideration payable ...... (63) Residual goodwill ...... 5,417 Share of loss ...... (131) Carrying value of investment ...... 15,601 Share of associates revenues and net loss: Revenue ...... — Net loss ...... (131)

F-178 Notes to the consolidated financial statements continued For the year ended 31 December 2010

15 Interest in joint ventures In the normal course of business, the group establishes jointly controlled entities for the execution of certain of its operations and contracts. A list of these joint ventures is disclosed in note 35. The group’s share of assets, liabilities, revenues and expenses relating to jointly controlled entities is as follows:

2010 2009 US$’000 US$’000 Revenue ...... 194,848 31,573 Cost of sales ...... (171,233) (28,293) Gross profit ...... 23,615 3,280 Selling, general and administration expenses ...... (14,286) (16,374) Other (expense)/income, net ...... (6,553) 47 Finance income, net ...... 643 5 Profit/(loss) before income tax ...... 3,419 (13,042) Income tax ...... (263) (268) Net profit/(loss) ...... 3,156 (13,310)

Current assets ...... 94,935 61,677 Non-current assets ...... 27,634 4,830 Total assets ...... 122,569 66,507

Current liabilities ...... 120,892 64,619 Non-current liabilities ...... 1,658 3,686 Total liabilities ...... 122,550 68,305 Net assets/(liabilities) ...... 19 (1,798)

16 Available-for-sale financial assets

2010 2009 US$’000 US$’000 Seven Energy International Limited ...... 101,251 — Shares – listed ...... 243 — Units in a mutual fund ...... — 539 101,494 539

On 25 November 2010, the group paid US$101,251,000 for 15% (12.6% on a fully diluted basis) of the share capital of Seven Energy International Limited (Seven Energy), a leading Nigerian gas development and production company. The group also has the option to subscribe for 148,571 `of additional warrants in Seven Energy at a cost of a further US$52,000,000, subject to the satisfaction of certain performance conditions and milestones in relation to project execution. These warrants have been fair valued as derivative financial instruments under IAS 39 using a Black Scholes Model and are included in other financial assets (note 17) with a corresponding entry in trade and other payables representing deferred revenue relating to the performance conditions. This will be recognised as a gain once the warrants become exercisable.

F-179 Notes to the consolidated financial statements continued For the year ended 31 December 2010

17 Other financial assets

2010 2009 US$’000 US$’000 Other financial assets – non-current Fair value of derivative instruments (note 33) ...... 12 9,655 Restricted cash ...... 266 2,880 Other ...... 1,945 — 2,223 12,535 Other financial assets – current Seven Energy warrants (note 16) ...... 11,969 — Fair value of derivative instruments (note 33) ...... 9,183 22,306 Interest receivable ...... 731 845 Restricted cash ...... 19,196 7,431 Other ...... 1,271 375 42,350 30,957

Restricted cash comprises deposits with financial institutions securing various guarantees and performance bonds associated with the group’s trading activities (note 31). This cash will be released on the maturity of these guarantees and performance bonds.

18 Inventories

2010 2009 US$’000 US$’000 Crude oil ...... 2,119 5,272 Processed hydrocarbons ...... 90 31 Stores and spares ...... 4,083 2,943 Raw materials ...... 910 1,552 7,202 9,798

Included in the consolidated income statement are costs of inventories expensed of US$28,840,000 (2009: US$37,306,000).

19 Work in progress and billings in excess of cost and estimated earnings

2010 2009 US$’000 US$’000 Cost and estimated earnings ...... 7,812,897 3,918,368 Less: billings ...... (7,008,911) (3,584,670) Work in progress ...... 803,986 333,698

Billings ...... 2,144,252 3,406,412 Less: cost and estimated earnings ...... (1,965,823) (2,945,268) Billings in excess of cost and estimated earnings ...... 178,429 461,144 Total cost and estimated earnings ...... 9,778,720 6,863,636 Total billings ...... 9,153,163 6,991,082

F-180 Notes to the consolidated financial statements continued For the year ended 31 December 2010

20 Trade and other receivables

2010 2009 US$’000 US$’000 Trade receivables ...... 785,383 614,837 Retentions receivable ...... 26,297 8,772 Advances ...... 179,101 139,550 Prepayments and deposits ...... 34,059 35,143 Other receivables ...... 31,919 80,368 1,056,759 878,670

2010 2009 Specific General Specific General impairment impairment Total impairment impairment Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 At 1 January ...... 4,875 1,754 6,629 3,698 1,296 4,994 Charge for the year ...... 2,189 1,796 3,985 6,309 1,320 7,629 Amounts written off ...... (2,197) (67) (2,264) (343) (198) (541) Unused amounts reversed ...... (1,738) (893) (2,631) (4,798) (661) (5,459) Transfers ...... (326) 326 — ——— Exchange difference ...... (13) 19 6 9 (3) 6 At 31 December ...... 2,790 2,935 5,725 4,875 1,754 6,629

At 31 December, the analysis of trade receivables is as follows:

Neither past Number of days past due due nor <30 31-60 61-90 91-120 121-360 > 360 impaired days days days days days days Total US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Unimpaired ...... 599,661 125,821 34,562 10,897 7,324 834 164 779,263 Impaired ...... — 3,230 1,085 157 1,633 4,023 1,717 11,845 599,661 129,051 35,647 11,054 8,957 4,857 1,881 791,108 Less: impairment provision . . — (1,211) (391) (244) (774) (2,295) (810) (5,725) Net trade receivables 2010 ...... 599,661 127,840 35,256 10,810 8,183 2,562 1,071 785,383

Unimpaired ...... 434,159 116,197 28,835 13,365 3,431 5,977 2,138 604,102 Impaired ...... — 3,177 2,148 386 2,510 6,220 2,923 17,364 434,159 119,374 30,983 13,751 5,941 12,197 5,061 621,466 Less: impairment provision . . — (585) (243) (332) (305) (3,421) (1,743) (6,629) Net trade receivables 2009 . . . 434,159 118,789 30,740 13,419 5,636 8,776 3,318 614,837

Advances represent payments made to certain of the group’s sub-contractors for projects in progress, on which the related work had not been performed at the statement of financial position date. The increase in advances during 2010 relates to new contract awards in the Engineering & Construction business partly offset by the unwinding of advances on more mature contracts.

Included in other receivables are US$ nil (2009: US$46,697,000) recoverable from venture partners on the Don assets being their share of accrued expenses.

F-181 Notes to the consolidated financial statements continued For the year ended 31 December 2010

20 Trade and other receivables continued

All trade and other receivables are expected to be settled in cash.

Certain trade and other receivables will be settled in cash using currencies other than the reporting currency of the group, and will be largely paid in Sterling and Kuwaiti Dinars.

21 Cash and short-term deposits

2010 2009 US$’000 US$’000 Cash at bank and in hand ...... 244,018 203,105 Short-term deposits ...... 818,987 1,214,258 Total cash and bank balances ...... 1,063,005 1,417,363

Short-term deposits are made for varying periods of between one day and three months depending on the immediate cash requirements of the group, and earn interest at respective short-term deposit rates. The fair value of cash and bank balances is US$1,063,005,000 (2009: US$1,417,363,000).

For the purposes of the consolidated cash flow statement, cash and cash equivalents comprise the following:

2010 2009 US$’000 US$’000 Cash at bank and in hand ...... 244,018 203,105 Short-term deposits ...... 818,987 1,214,258 Bank overdrafts (note 26) ...... (28,908) (26,619) 1,034,097 1,390,744

22 Share capital The share capital of the Company as at 31 December was as follows:

2010 2009 US$’000 US$’000 Authorised 750,000,000 ordinary shares of US$0.020 each (2009: 750,000,000 ordinary shares of US$0.025 each) ...... 15,000 18,750

Issued and fully paid **345,715,053 ordinary shares of US$0.020 each (2009: 345,532,388 ordinary shares of US$0.025 each) ...... 6,914 8,638

The movement in the number of issued and fully paid ordinary shares is as follows:

Number Ordinary shares: Ordinary shares of US$0.025 each at 1 January 2009 ...... 345,434,858 Issued during the year as further deferred consideration payable for the acquisition of a subsidiary ...... 97,530 Ordinary shares of US$0.025 each at 1 January 2010 ...... 345,532,388 Issued during the year as further deferred consideration payable for the acquisition of subsidiaries ...... 182,665 Ordinary shares of US$0.020 each at 31 December 2010 ...... 345,715,053

F-182 Notes to the consolidated financial statements continued For the year ended 31 December 2010

22 Share capital continued

The share capital comprises only one class of ordinary shares. The ordinary shares carry a voting right and the right to a dividend.

** In order to effect the demerger of the PEDL sub group to EnQuest, the existing issued ordinary share capital of Petrofac Limited was subdivided and converted into new ordinary Petrofac shares with a nominal value of US$0.02 each and Petrofac B shares of US$0.005 each and subsequent to this share split the B shares were purchased and cancelled in exchange for an allotment and issue of EnQuest ordinary shares directly to holders of Petrofac B shares.

23 Treasury shares For the purpose of making awards under its employee share schemes, the Company acquires its own shares which are held by the Petrofac Employee Benefit Trust. All these shares have been classified in the statement of financial position as treasury shares within equity.

The movements in total treasury shares are shown below:

2010 2009 Number US$’000 Number US$’000 At 1 January ...... 7,210,965 56,285 9,540,306 69,333 Acquired during the year ...... 2,122,960 36,486 —— Vested during the year ...... (2,576,586) (27,454) (2,329,341) (13,048) At 31 December ...... 6,757,339 65,317 7,210,965 56,285

During the year 5,467,852 Petrofac shares previously held in a Lehman Brothers custody account pending the finalisation of their legal administration were released to the Employee Benefit Trust.

Shares vested during the year include dividend shares of 120,504 (2009: 76,931) with a cost of US$1,284,000 (2009: US$431,000).

24 Share-based payment plans Performance Share Plan (PSP) Under the Performance Share Plan of the Company, share awards are granted to executive directors and a restricted number of other senior executives of the group. The shares cliff vest at the end of three years subject to continued employment and the achievement of certain pre-defined non-market and market-based performance conditions. The non-market-based condition governing the vesting of 50% of the total award, is subject to achieving between 10% and 20% earning per share (EPS) growth targets over a three-year period. The fair values of the equity-settled award relating to the EPS part of the scheme are estimated based on the quoted closing market price per Company share at the date of grant with an assumed vesting rate per annum built into the calculation (subsequently trued up at year end based on the actual leaver rate during the period from award date to year end) over the three-year vesting period of the plan. The fair value and assumed vesting rates of the EPS part of the scheme are shown below:

Fair value Assumed per share vesting rate 2010 awards ...... 1,103p 95.0% 2009 awards ...... 545p 93.6% 2008 awards ...... 522p 89.1% 2007 awards ...... 415p 94.3%

The remaining 50% market performance based part of these awards is dependent on the total shareholder return (TSR) of the group compared to an index composed of selected relevant companies. The fair value of the shares

F-183 Notes to the consolidated financial statements continued For the year ended 31 December 2010

24 Share-based payment plans continued vesting under this portion of the award is determined by an independent valuer using a Monte Carlo simulation model taking into account the terms and conditions of the plan rules and using the following assumptions at the date of grant:

2010 awards 2009 awards 2008 awards 2007 awards Expected share price volatility (based on median of comparator group’s three-year volatilities) ...... 50.0% 49.0% 32.0% 29.0% Share price correlation with comparator group ...... 39.0% 36.0% 22.0% 17.0% Risk-free interest rate ...... 1.50% 2.10% 3.79% 5.20% Expected life of share award ...... 3 years 3 years 3 years 3 years Fair value of TSR portion ...... 743p 456p 287p 245p

The following shows the movement in the number of shares held under the PSP scheme outstanding but not exercisable:

2010 2009 Number Number Outstanding at 1 January ...... 1,432,680 1,298,809 Granted during the year ...... 390,278 576,780 Vested during the year ...... (407,316) (418,153) Forfeited during the year ...... (65,453) (24,756) Outstanding at 31 December ...... 1,350,189 1,432,680

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger (82,594 shares) and any rolled up declared dividends (64,264 shares) (2009: 60,830). The 8% uplift adjustment compensated the existing share plan holders for the loss in market value of Petrofac shares on flotation of EnQuest and employees have no legal right to receive dividend shares until the shares ultimately vest.

The number of awards still outstanding but not exercisable at 31 December 2010 is made up of 390,278 in respect of 2010 awards (2009: nil), 538,602 in respect of 2009 awards (2009: 576,780), 421,309 in respect of 2008 awards (2009: 431,843), and nil in respect of 2007 awards (2009: 424,057).

The charge recognised in the current year amounted to US$3,208,000 (2009: US$2,727,000).

Deferred Bonus Share Plan (DBSP) Executive directors and selected employees were originally eligible to participate in this scheme although the Remuneration Committee decided in 2007 that executive directors should no longer continue to participate. Participants are required, or in some cases invited, to receive a proportion of any bonus in ordinary shares of the Company (‘Invested Awards’). Following such an award, the Company will generally grant the participant an additional award of a number of shares bearing a specified ratio to the number of his or her invested shares (‘Matching Shares’).

A change in the rules of the DBSP scheme was approved by shareholders at the Annual General Meeting of the Company on 11 May 2007 such that the 2007 share awards and for any awards made thereafter, the invested and Matching Shares would, unless the Remuneration Committee of the Board of Directors determined otherwise, vest 33.33% on the first anniversary of the date of grant, a further 33.33% on the second anniversary of the date of grant and the final 33.34% of the award on the third anniversary of the date of grant.

F-184 Notes to the consolidated financial statements continued For the year ended 31 December 2010

24 Share-based payment plans continued liability to be settled in shares is transferred to the reserve for share-based payments. The costs relating to the Matching Shares are recognised over the relevant vesting period and the fair values of the equity-settled Matching Shares granted to employees are based on the quoted closing market price at the date of grant adjusted for the trued up percentage vesting rate of the plan. The details of the fair values and assumed vesting rates of the DBSP scheme are below:

Fair value Assumed per share vesting rate 2010 awards ...... 1,185p 94.4% 2009 awards ...... 545p 93.9% 2008 awards ...... 522p 90.9% 2007 awards ...... 415p 89.6%

The following shows the movement in the number of shares held under the DBSP scheme outstanding but not exercisable:

2010 2009 Number* Number* Outstanding at 1 January ...... 4,694,191 3,755,383 Granted during the year ...... 1,397,094 2,773,020 Vested during the year ...... (1,792,895) (1,743,372) Forfeited during the year ...... (216,079) (90,840) Outstanding at 31 December ...... 4,082,311 4,694,191

* Includes Invested and Matching Shares.

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger (327,058 shares) and rolled up declared dividends of 184,599 (2009: 169,836).

The number of awards still outstanding but not exercisable at 31 December 2010 is made up of 1,313,894 in respect of 2010 awards (2009: nil), 1,948,340 in respect of 2009 awards (2009: 2,696,752), 820,077 in respect of 2008 awards (2009: 1,237,786), and nil in respect of 2007 awards (2009: 759,653).

The charge recognised in the 2010 income statement in relation to matching share awards amounted to US$9,195,000 (2009: US$8,064,000).

Share Incentive Plan (SIP) All UK employees, including UK resident directors, are eligible to participate in the scheme. Employees may invest up to Sterling 1,500 per tax year of gross salary (or, if lower, 10% of salary) to purchase ordinary shares in the Company. There is no holding period for these shares.

F-185 Notes to the consolidated financial statements continued For the year ended 31 December 2010

24 Share-based payment plans continued

Weighted average fair Assumed value per share vesting rate 2010 awards ...... 990p 95.8% 2009 awards ...... 430p 69.4% 2008 awards ...... 478p 88.0% 2007 awards ...... 456p 94.3%

The following shows the movement in the number of shares held under the RSP scheme outstanding but not exercisable:

2010 2009 Number Number Outstanding at 1 January ...... 1,082,461 1,184,711 Granted during the year ...... 203,384 86,432 Vested during the year ...... (176,360) (167,053) Forfeited during the year ...... (105,773) (21,629) Outstanding at 31 December ...... 1,003,712 1,082,461

The number of outstanding shares exclude the 8% uplift adjustment made in respect of the EnQuest demerger (78,156 shares) and rolled up declared dividends of 48,474 (2009: 33,691).

The number of awards still outstanding but not exercisable at 31 December 2010 is made up of 195,580 in respect of 2010 awards (2009: nil), 36,658 in respect of 2009 awards (2009: 86,432), 665,542 in respect of 2008 awards (2009: 786,826), and 105,932 in respect of 2007 awards (2009: 209,203).

During the year the Company recognised a charge of US$2,381,000 (2009: US$2,472,000) in relation to the above.

The group has recognised a total charge of US$14,784,000 (2009: US$13,263,000) in the consolidated income statement during the year relating to the above employee share-based schemes (see note 4d) which has been transferred to the reserve for share-based payments along with US$12,750,000 of the bonus liability accrued for the year ended 31 December 2009 which has been settled in shares granted during the year (2009: US$10,942,000).

For further details on the above employee share-based payment schemes refer to pages 88 to 90 of the directors’ remuneration report.

F-186 Notes to the consolidated financial statements continued For the year ended 31 December 2010

25 Other reserves

Net unrealised gains/(losses) Net unrealised on available-for- (losses)/ Foreign Reserve for sale-financial gains on currency share-based assets derivatives translation payments Total US$’000 US$’000 US$’000 US$’000 US$’000 Balance at 1 January 2009 ...... 74 7,847 (79,415) 32,202 (39,292) Foreign currency translation ...... — — 15,087 — 15,087 Net gains on maturity of cash flow hedges recycled in the year ...... — (4,303) — — (4,303) Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... — 29,229 — — 29,229 Share-based payments charge (note 24) ...... — — — 13,263 13,263 Transfer during the year (note 24) ...... — — — 10,942 10,942 Shares vested during the year (note 24) ...... — — — (12,617) (12,617) Deferred tax on share based payments reserve ...... — — — 13,085 13,085 Balance at 1 January 2010 ...... 74 32,773 (64,328) 56,875 25,394 Foreign currency translation ...... — — (908) — (908) Foreign currency translation recycled to consolidated income statement in the year on EnQuest demerger (note 11) ...... — — 45,818 — 45,818 Net gains on maturity of cash flow hedges recycled in the year ...... — (16,612) — — (16,612) Net changes in fair value of derivatives and financial assets designated as cash flow hedges ...... — (18,958) — — (18,958) Net changes in fair value of available-for-sale financial assets ...... 70 — — — 70 Disposal of available-for-sale financial assets ...... (74) — — — (74) Share-based payments charge (note 24) ...... — — — 14,784 14,784 Transfer during the year (note 24) ...... — — — 12,750 12,750 Shares vested during the year (note 24) ...... — — — (26,170) (26,170) Deferred tax on share based payments reserve ...... — — — (1,366) (1,366) Balance at 31 December 2010 ...... 70 (2,797) (19,418) 56,873 34,728

Nature and purpose of other reserves Net unrealised gains/(losses) on available-for-sale financial assets This reserve records fair value changes on available-for-sale financial assets held by the group net of deferred tax effects. Realised gains and losses on the sale of available-for-sale financial assets are recognised as other income or expenses in the consolidated income statement.

Net unrealised gains/(losses) on derivatives The portion of gains or losses on cash flow hedging instruments that are determined to be effective hedges are included within this reserve net of related deferred tax effects. When the hedged transaction occurs or is no longer forecast to occur, the gain or loss is transferred out of equity to the consolidated income statement. Realised net gains amounting to US$16,764,000 (2009: US$5,161,000) relating to foreign currency forward contracts and financial assets designated as cash flow hedges have been recognised in cost of sales, realised net losses of US$ nil (2009: US$1,470,000 loss) relating to interest rate derivatives have been classified as a net interest expense and a realised net loss of US$152,000 (2009: US$611,000 gain) was added to revenues in respect of oil derivatives.

The forward currency points element and ineffective portion of derivative financial instruments relating to forward currency contracts and gains on the maturity of un-designated derivatives amounting to a net loss of US$3,409,000 (2009: US$19,508,000 gain) have been recognised in the cost of sales.

F-187 Notes to the consolidated financial statements continued For the year ended 31 December 2010

25 Other reserves continued

Reserve for share-based payments The reserve for share-based payments is used to record the value of equity settled share-based payments awarded to employees and transfers out of this reserve are made upon vesting of the original share awards.

The transfer during the year reflects the transfer from accrued expenses within trade and other payables of the bonus liability relating to the year ended 2009 of US$12,750,000 (2008 bonus of US$10,942,000) which has been voluntarily elected or mandatorily obliged to be settled in shares during the year (note 24).

26 Interest-bearing loans and borrowings

The group had the following interest-bearing loans and borrowings outstanding:

31 December 2010 31 December 2009 Effective 2010 2009 Actual interest rate % Actual interest rate % interest rate % Maturity US$’000 US$’000 Current Revolving credit facility ..... (i) n/a US LIBOR +1.50% US LIBOR +1.50% — 20,000 Bank overdrafts ...... (ii) UK LIBOR +1.50%, UK LIBOR +1.50%, UK LIBOR +1.50%, on demand 28,908 26,619 US LIBOR +1.50% US LIBOR +1.50% US LIBOR +1.50% Other loans: Current portion of term loan ...... (iii) US/UK LIBOR US/UK LIBOR 3.26% to 4.14% 14,241 10,489 +0.875% +0.875% (2009: 3.14% to 3.71%) Current portion of term loan ...... (iv) US/UK LIBOR US/UK LIBOR 2.01% to 3.91% 4,286 963 +0.875% +0.875% (2009: 2.65% to 3.44%) 47,435 58,071

Non-current Term loan ...... (iv) US/UK LIBOR US/UK LIBOR 2.01% to 3.91% 2010-2013 13,809 18,291 +0.875% +0.875% (2009: 2.65% to 3.44%)

Term loan ...... (iii) US/UK LIBOR US/UK LIBOR 3.26% to 4.14% 2010-2013 30,576 46,694 +0.875% +0.875% (2009: 3.14% to 3.71%) 44,385 64,985 Less: Debt acquisition costs net of accumulated amortisation and effective rate adjustments ...... (4,159) (5,790) 40,226 59,195

Details of the group’s interest-bearing loans and borrowings are as follows:

(i) Revolving credit facility This facility has been repaid on 31 December 2010.

F-188 Notes to the consolidated financial statements continued For the year ended 31 December 2010

26 Interest-bearing loans and borrowings continued

(ii) Bank overdrafts Bank overdrafts are drawn down in US Dollars and Sterling denominations to meet the group’s working capital requirements. These are repayable on demand.

(iii) Term loan This term loan at 31 December 2010 comprised drawings of US$23,057,000 (2009: US$28,877,000) denominated in US$ and US$21,760,000 (2009: US$28,306,000) denominated in Sterling. Both elements of the loan are repayable over a period of three years ending 30 September 2013.

(iv) Term loan This term loan is to be repaid over a period of three years ending 30 September 2013. The drawings at 31 December 2010 comprised US$13,203,000 (2009: US$13,900,000) denominated in US$ and US$4,892,000 (2009: US$5,354,000) denominated in Sterling.

The group’s credit facilities and debt agreements contain covenants relating to interest and net borrowings cover. 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.

27 Provisions

Other long-term Provision Provision for employment for insurance benefits provision decommissioning claims Total US$’000 US$’000 US$’000 US$’000 At 1 January 2010 ...... 34,130 57,973 — 92,103 Additions during the year ...... 12,770 984 1,561 15,315 Don assets demerger (note 11) ...... — (55,967) — (55,967) Unused amounts reversed/paid in the year ...... (6,696) (90) — (6,786) Unwinding of discount ...... — 776 — 776 At 31 December 2010 ...... 40,204 3,676 1,561 45,441

Other long-term employment benefits provision Labour laws in certain countries in which the group operates require employers to provide for other long-term employment benefits. These benefits are payable to employees on being transferred to another jurisdiction or on cessation of employment.

Provision for decommissioning The decommissioning provision primarily relates to the group’s obligation for the removal of facilities and restoration of the site at the PM304 field in Malaysia and at Chergui in Tunisia. The liability is discounted at the rate of 3.80% on PM304 (2009: 3.80%), 5.25% on Chergui (2009: 5.25%) and nil% (2009: 4.50%) on demerged Don assets. The unwinding of the discount is classified as finance cost (note 5). The group estimates that the cash outflows against these provisions will arise in 2014 on PM304 and in 2018 on Chergui.

Provision for insurance claims The provision for insurance claims relates to the amount set aside to cover potential future insurance claims against the group which will be settled by the captive insurance company Jermyn Insurance Company Limited.

F-189 Notes to the consolidated financial statements continued For the year ended 31 December 2010

28 Other financial liabilities

2010 2009 US$’000 US$’000 Other financial liabilities – non-current Deferred consideration payable ...... 11,279 27,438 Fair value of derivative instruments (note 33) ...... 174 — Other ...... — 47 11,453 27,485 Other financial liabilities – current Deferred consideration payable ...... 24,595 1,622 Interest payable ...... 9 22 Fair value of derivative instruments (note 33) ...... 12,197 1,813 Other ...... 253 177 37,054 3,634

Included in deferred consideration payable above is an amount payable of US$3,918,000 (2009: US$4,890,000) relating to the group’s purchase of a floating platform and US$6,556,000 (2009: US$ nil) relating to the group’s investment in an associate (note 14).

29 Trade and other payables

Restated 2010 2009 US$’000 US$’000 Trade payables ...... 278,383 292,414 Advances received from customers ...... 412,044 379,684 Accrued expenses ...... 251,512 260,290 Other taxes payable ...... 12,755 14,699 Other payables ...... 66,742 29,930 1,021,436 977,017

Advances from customers represent payments received for contracts on which the related work had not been performed at the statement of financial position date.

Included in other payables are retentions held against subcontractors of US$6,170,000 (2009: US$938,000). Also included in other payables above is U$11,969,000 deferred revenue relating to the provision of services required to earn the right to subscribe for the additional Seven Energy warrants (note 16).

Certain trade and other payables will be settled in currencies other than the reporting currency of the group, mainly in Sterling, Euros and Kuwaiti Dinars.

30 Accrued contract expenses

2010 2009 US$’000 US$’000 Accrued contract expenses ...... 1,272,942 832,503 Reserve for contract losses ...... 2,523 4,153 1,275,465 836,656

The reserve for contract losses is to cover costs in excess of revenues on certain contracts.

F-190 Notes to the consolidated financial statements continued For the year ended 31 December 2010

31 Commitments and contingencies Commitments In the normal course of business the group will obtain surety bonds, letters of credit and guarantees, which are contractually required to secure performance, advance payment or in lieu of retentions being withheld. Some of these facilities are secured by issue of corporate guarantees by the Company in favour of the issuing banks.

At 31 December 2010, the group had letters of credit of US$2,984,000 (2009: US$91,042,000) and outstanding letters of guarantee, including performance, advance payments and bid bonds, of US$2,951,553,000 (2009: US$2,124,134,000) against which the group had pledged or restricted cash balances of, in aggregate, US$19,462,000 (2009: US$2,675,000).

At 31 December 2010, the group had outstanding forward exchange contracts amounting to US$188,561,000 (2009: US$351,803,000). These commitments consist of future obligations to either acquire or sell designated amounts of foreign currency at agreed rates and value dates (note 33).

Leases The group has financial commitments in respect of non-cancellable operating leases for office space and equipment. These non-cancellable leases have remaining non-cancellable lease terms of between one and 17 years and, for certain property leases, are subject to renegotiation at various intervals as specified in the lease agreements. The future minimum rental commitments under these non-cancellable leases are as follows:

2010 2009 US$’000 US$’000 Within one year ...... 18,031 35,796 After one year but not more than five years ...... 41,239 57,127 More than five years ...... 76,914 73,030 136,184 165,953

Included in the above are commitments relating to the lease of an office building extension in Aberdeen, United Kingdom of US$49,232,000 (2009: US$39,735,000), lease of mobile operating production unit and floating storage and offloading unit US$15,619,000 (2009: US$35,665,000) in Block PM304, offshore Malaysia and mobile drilling rig for the Don Southwest project of US$ nil (2009: US$10,089,000).

Minimum lease payments recognised as an operating lease expense during the year amounted to US$35,625,000 (2009: US$33,063,000).

Capital commitments At 31 December 2010, the group had capital commitments of US$90,416,000 (2009: US$18,786,000) excluding the above lease commitments.

Included in the above are commitments to refurbish the floating production, storage and offloading unit for East Fortune of US$52,800,000 (2009: US$ nil), further appraisal and development of wells as part of the Cendor project in Malaysia amounting to US$7,269,000 (2009: US$14,572,000), commitments in respect of the Ticleni Production Enhancement contract in Romania US$21,046,000 (2009: US$ nil) and commitments in respect of IT projects of US$9,281,000 (2009: US$3,300,000).

32 Related party transactions The consolidated financial statements include the financial statements of Petrofac Limited and the subsidiaries listed in note 35. Petrofac Limited is the ultimate parent entity of the group.

F-191 Notes to the consolidated financial statements continued For the year ended 31 December 2010

32 Related party transactions continued

The following table provides the total amount of transactions which have been entered into with related parties:

Amounts owed Sales to related Purchases from by related Amounts owed parties related parties parties to related parties US$’000 US$’000 US$’000 US$’000 Joint ventures ...... 2010 101,370 88,796 327 11,098 2009 27,337 15,434 17,773 56,925 Key management personnel interests .... 2010 — 1,688 — 612 2009 — 1,405 487 401

All sales to and purchases from joint ventures are made at normal market prices and the pricing policies and terms of these transactions are approved by the group’s management.

All related party balances will be settled in cash.

Purchases in respect of key management personnel interests of US$1,601,000 (2009: US$1,336,000) reflect the market rate based costs of chartering the services of an aeroplane used for the transport of senior management and directors of the group on company business, which is owned by an offshore trust of which the Group Chief Executive of the Company is a beneficiary.

Also included in purchases in respect of key management personnel interests is US$87,000 (2009: US$69,000) relating to client entertainment provided by a business owned by a member of the group’s key management.

Amounts owed by key management personnel comprises of a temporary loan of US$ nil (2009: US$487,000) provided in respect of income tax payable on vesting of Restricted Share Plan shares pending disposal of shares to meet this liability once the close period for trading Petrofac shares ends.

Compensation of key management personnel The following details remuneration of key management personnel of the group comprising of executive and non- executive directors of the Company and other senior personnel. Further information relating to the individual directors is provided in the directors’ remuneration report on pages 84 to 95.

2010 2009 US$’000 US$’000 Short-term employee benefits ...... 11,870 11,209 Other long-term employment benefits ...... 142 129 Share-based payments ...... 3,827 3,368 Fees paid to non-executive directors ...... 581 506 16,420 15,212

33 Risk management and financial instruments Risk management objectives and policies The group’s principal financial assets and liabilities, other than derivatives, comprise available-for-sale financial assets, trade and other receivables, amounts due from/to related parties, cash and short-term deposits, work-in- progress, interest-bearing loans and borrowings, trade and other payables and deferred consideration.

The group’s activities expose it to various financial risks particularly associated with interest rate risk on its variable rate cash and short-term deposits, loans and borrowings and foreign currency risk on both conducting business in currencies other than reporting currency as well as translation of the assets and liabilities of foreign operations to the reporting currency. These risks are managed from time to time by using a combination of various derivative instruments, principally interest rate swaps, caps and forward currency contracts in line with the group’s hedging policies. The group has a policy not to enter into speculative trading of financial derivatives.

F-192 Notes to the consolidated financial statements continued For the year ended 31 December 2010

33 Risk management and financial instruments continued

The Board of Directors of the Company has established an Audit Committee and Risk Committee to help identify, evaluate and manage the significant financial risks faced by the group and their activities are discussed in detail on pages 80 to 83.

The other main risks besides interest rate and foreign currency risk arising from the group’s financial instruments are credit risk, liquidity risk and commodity price risk and the policies relating to these risks are discussed in detail below:

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 arising from changes in interest rates relates primarily to the group’s long- term variable rate debt obligations and its cash and bank balances. The group’s policy is to manage its interest cost using a mix of fixed and variable rate debt. The group’s cash and bank balances are at floating rates of interest.

Interest rate sensitivity analysis The impact on the group’s pre-tax profit and equity due to a reasonably possible change in interest rates on loans and borrowings at the reporting date is demonstrated in the table below. The analysis assumes that all other variables remain constant.

Pre-tax profit Equity 100 basis 100 basis 100 basis 100 basis point increase point decrease point increase point decrease US$’000 US$’000 US$’000 US$’000 31 December 2010 ...... (710) 710 — — 31 December 2009 ...... (1,096) 1,096 — —

The following table reflects the maturity profile of these financial liabilities and assets:

Within 1-2 2-3 3-4 4-5 More than 1 year years years years years 5 years Total Year ended 31 December 2010 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Financial liabilities Floating rates Bank overdrafts (note 26) ...... 28,908 — — — — — 28,908 Term loans (note 26) ...... 18,527 23,823 20,562 — — — 62,912 47,435 23,823 20,562 — — — 91,820 Financial assets Floating rates Cash and short-term deposits (note 21)...... 1,063,005 — — — — — 1,063,005 Restricted cash balances (note 17) . . . 19,196 266 — — — — 19,462 1,082,201 266 — — — — 1,082,467

F-193 Notes to the consolidated financial statements continued For the year ended 31 December 2010

33 Risk management and financial instruments continued

Within 1-2 2-3 3-4 4-5 More than 1 year years years years years 5 years Total Year ended 31 December 2009 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Financial liabilities Floating rates Revolving credit facility (note 26) . . . 20,000 — — — — — 20,000 Bank overdrafts (note 26) ...... 26,619 — — — — — 26,619 Term loans (note 26) ...... 11,452 18,901 24,221 21,863 — — 76,437 58,071 18,901 24,221 21,863 — — 123,056 Financial assets Floating rates Cash and short-term deposits (note 21)...... 1,417,363 — — — — — 1,417,363 Restricted cash balances (note 17) . . . 7,431 226 — — — 2,654 10,311 1,424,794 226 — — — 2,654 1,427,674

Financial liabilities in the above table are disclosed gross of debt acquisition costs and effective rate adjustments of US$4,159,000 (2009: US$5,790,000).

Interest on financial instruments classified as floating rate is re-priced at intervals of less than one year. The other financial instruments of the group that are not included in the above tables are non-interest bearing and are therefore not subject to interest rate risk.

Derivative instruments designated as cash flow hedges At 31 December 2010, the group held no derivative instruments, designated as cash flow hedges in relation to floating rate interest-bearing loans and borrowings.

Foreign currency risk The group is exposed to foreign currency risk on sales, purchases, and translation of assets and liabilities that are in a currency other than the functional currency of its operating units. The group is also exposed to the translation of the functional currencies of its units to the US Dollar reporting currency of the group. The following table summarises the percentage of foreign currency denominated revenues, costs, financial assets and financial liabilities, expressed in US Dollar terms, of the group totals.

2010 2009 % of foreign % of foreign currency currency denominated denominated items items Revenues ...... 41.6% 39.5% Costs ...... 62.2% 50.1% Current financial assets ...... 34.8% 35.3% Non-current financial assets ...... 0.0% 1.0% Current financial liabilities ...... 51.2% 42.3% Non-current financial liabilities ...... 59.4% 34.6%

The group uses forward currency contracts to manage the currency exposure on transactions significant to its operations. It is the group’s policy not to enter into forward contracts until a highly probable forecast transaction is in place and to negotiate the terms of the derivative instruments used for hedging to match the terms of the hedged item to maximise hedge effectiveness.

F-194 Notes to the consolidated financial statements continued For the year ended 31 December 2010

33 Risk management and financial instruments continued reporting date. Revenues and costs in currencies other than the functional currency of an operating unit are recorded at the prevailing rate at the date of the transaction. The following significant exchange rates applied during the year in relation to US Dollars:

2010 2009 Average rate Closing rate Average rate Closing rate Sterling ...... 1.54 1.56 1.56 1.62 Kuwaiti Dinar ...... 3.49 3.55 3.47 3.48 Euro ...... 1.32 1.34 1.40 1.44

The following table summarises the impact on the group’s pre-tax profit and equity (due to change in the fair value of monetary assets, liabilities and derivative instruments) of a reasonably possible change in US Dollar exchange rates with respect to different currencies:

Pre-tax profit Equity +10% US Dollar -5% US Dollar +10% US Dollar -5% US Dollar rate increase rate decrease rate increase rate decrease US$’000 US$’000 US$’000 US$’000 31 December 2010 ...... (3,750) 1,875 6,272 (3,136) 31 December 2009 ...... (10,238) 5,141 7,980 (3,990)

Derivative instruments designated as cash flow hedges At 31 December 2010, the group had foreign exchange forward contracts as follows:

Fair value Fair value Net unrealised Contract value (undesignated) (designated) gain/(loss) 2010 2009 2010 2009 2010 2009 2010 2009 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Euro currency purchases ...... 171,072 101,909 (1,794) 5,017 (2,046) 24,479 (1,827) 28,430 Sterling currency purchases ...... 14,405 38,700 (135) — 1,583 4,703 1,695 4,966 Yen currency purchases (sales) ...... 1,721 (160) 128 — 76 (942) 117 (862) Swiss Francs purchases ...... 1,363 — — — 175 — 14 — Kuwaiti Dinars sales ...... — (211,034) — 53 — (1,349) — 266 (1) 32,800

The above foreign exchange contracts mature and will affect income between January 2011 and July 2013 (2009: between January 2010 and July 2013).

At 31 December 2010, the group had cash and short-term deposits designated as cash flow hedges with a fair value loss of US$1,633,000 (2009: US$1,786,000 gain) as follows:

Fair value Net unrealised gain/(loss) 2010 2009 2010 2009 US$’000 US$’000 US$’000 US$’000 Euro currency cash and short-term deposits ...... 15,730 91,660 (1,798) 1,163 Sterling currency cash and short-term deposits ...... 2,086 5,264 (120) 772 Yen currency cash and short-term deposits ...... 4,510 — 278 — Swiss Francs cash and short-term deposits ...... 660 — 7 — Kuwaiti Dinars cash and short-term deposits ...... — 19,146 — (149) (1,633) 1,786

During 2010, changes in fair value losses of US$19,456,000 (2009: losses US$28,043,000) relating to these derivative instruments and financial assets were taken to equity and US$16,764,000 of gains (2009: US$5,161,000 gains) were recycled from equity into cost of sales in the income statement. The forward points and ineffective portions of the above foreign exchange forward contracts and loss on maturity of un-designated derivatives of US$3,409,000 (2009: US$19,508,000 gains) were recognised in the income statement (note 4b).

F-195 Notes to the consolidated financial statements continued For the year ended 31 December 2010

33 Risk management and financial instruments continued

Commodity price risk – oil prices The group is exposed to the impact of changes in oil & gas prices on its revenues and profits generated from sales of crude oil & gas. The group’s policy is to manage its exposure to the impact of changes in oil and gas prices using derivative instruments, primarily swaps and collars. Hedging is only undertaken once sufficiently reliable and regular long term forecast production data is available.

During the year the group entered into various crude oil swaps hedging oil production of 176,400 bbl (2009: 96,000 bbl) with maturities ranging from 1 April 2010 to 31 December 2011. In addition, fuel oil swaps were also entered into for hedging gas production of 43,750MT (2009: 27,000MT) with maturities from 1 April 2010 to 31 December 2011.

The fair value of oil derivatives at 31 December 2010 was US$1,163,000 liability (2009: US$1,813,000 liability) with a loss recognised in equity of US$1,163,000 (2009: US$1,813,000 loss). During the year, a loss of US$152,000 (2009: US$611,000 gain) was recognised in the consolidated income statement on the occurrence of the hedged transactions.

The following table summarises the impact on the group’s pre-tax profit and equity (due to a change in the fair value of oil derivative instruments and the underlifting asset/overlifting liability) of a reasonably possible change in the oil price:

Pre-tax profit Equity +10 US$/bbl -10 US$/bbl +10 US$/bbl -10 US$/bbl increase decrease increase decrease US$’000 US$’000 US$’000 US$’000 31 December 2010 ...... (194) 194 (802) 802 31 December 2009 ...... 82 (82) (861) 861

Credit risk The group trades only with recognised, creditworthy third parties. Business Unit Risk Review Committees (BURRC) have been set up by the Board of Directors to evaluate the creditworthiness of each individual third party at the time of entering into new contracts. Limits have been placed on the approval authority of the BURRC above which the approval of the Board of Directors of the Company is required. Receivable balances are monitored on an ongoing basis with appropriate follow-up action taken where necessary. At 31 December 2010, the group’s five largest customers accounted for 72.0% of outstanding trade receivables and work in progress (2009: 57.5%).

With respect to credit risk arising from the other financial assets of the group, which comprise cash and cash equivalents, available-for-sale financial assets and certain derivative instruments, the group’s exposure to credit risk arises from default of the counterparty, with a maximum exposure equal to the carrying amount of these instruments.

F-196 Notes to the consolidated financial statements continued For the year ended 31 December 2010

33 Risk management and financial instruments continued

Liquidity risk The group’s objective is to maintain a balance between continuity of funding and flexibility through the use of overdrafts, revolving credit facilities, project finance and term loans to reduce its exposure to liquidity risk. The maturity profiles of the group’s financial liabilities at 31 December 2010 are as follows:

More Contractual 6 months 6-12 1-2 2-5 than undiscounted Carrying or less months years years 5 years cash flows amount Year ended 31 December 2010 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Financial liabilities Interest-bearing loans and borrowings ...... 37,776 9,659 23,823 20,562 — 91,820 87,661 Trade and other payables (excluding advances from customers) ...... 551,233 58,159 — — — 609,392 609,392 Due to related parties ...... 11,710 — — — — 11,710 11,710 Deferred consideration ...... 24,595 — 11,279 — — 35,874 35,874 Derivative instruments ...... 11,034 1,163 174 — — 12,371 12,371 Interest payable ...... 9 — — — — 9 9 Interest payments ...... 421 388 632 206 — 1,647 — 636,778 69,369 35,908 20,768 — 762,823 757,017

More Contractual 6 months 6-12 1-2 2-5 than undiscounted Carrying or less months years years 5 years cash flows amount Year ended 31 December 2009 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 Financial liabilities Interest-bearing loans and borrowings ...... 31,863 26,208 18,901 46,084 — 123,056 117,266 Trade and other payables (excluding advances from customers) ...... 585,490 11,843 — — — 597,333 597,333 Due to related parties ...... 44,496 12,830 — — — 57,326 57,326 Deferred consideration ...... 1,622 — 20,519 11,356 — 33,497 29,060 Derivative instruments ...... 907 906 — — — 1,813 1,813 Interest payable ...... 22 — — — — 22 22 Interest payments ...... 816 1,148 2,094 2,291 — 6,349 — 665,216 52,935 41,514 59,731 — 819,396 802,820

The group uses various funded facilities provided by banks and its own financial assets to fund the above mentioned financial liabilities.

F-197 Notes to the consolidated financial statements continued For the year ended 31 December 2010

33 Risk management and financial instruments continued

Capital management The group’s policy is to maintain a healthy capital base to sustain future growth and maximise shareholder value.

The group seeks to optimise shareholder returns by maintaining a balance between debt and capital and monitors the efficiency of its capital structure on a regular basis. The gearing ratio and return on shareholders’ equity is as follows:

Restated 2010 2009 US$’000 US$’000 Cash and short-term deposits ...... 1,063,005 1,417,363 Interest-bearing loans and borrowings (A) ...... (87,661) (117,266) Net cash (B) ...... 975,344 1,300,097 Equity attributable to Petrofac Limited shareholders (C) ...... 776,462 894,710 Profit for the year attributable to Petrofac Limited shareholders (D) ...... 557,817 353,603 Gross gearing ratio (A/C) ...... 11.3% 13.1% Net gearing ratio (B/C) ...... Net cash Net cash position position Shareholders’ return on investment (D/C) ...... 71.8% 39.5%

Fair values of financial assets and liabilities The fair value of the group’s financial instruments and their carrying amounts included within the group’s statement of financial position are set out below:

Carrying amount Fair value 2010 2009 2010 2009 US$’000 US$’000 US$’000 US$’000 Financial assets Cash and short-term deposits ...... 1,063,005 1,417,363 1,063,005 1,417,363 Restricted cash ...... 19,462 10,311 19,462 10,311 Available-for-sale financial assets ...... 101,494 539 101,494 539 Seven Energy warrants ...... 11,969 — 11,969 — Forward currency contracts-designated as cash flow hedge .... 7,961 26,891 7,961 26,891 Forward currency contracts-undesignated ...... 1,234 5,070 1,234 5,070

Financial liabilities Interest-bearing loans and borrowings ...... 87,661 117,266 87,661 117,266 Deferred consideration ...... 35,874 30,178 35,874 30,178 Oil derivative ...... 1,163 1,813 1,163 1,813 Forward currency contracts-designated as cash flow hedge .... 8,173 — 8,173 — Forward currency contracts-undesignated ...... 3,035 — 3,035 —

Fair values of financial assets and liabilities Market values have been used to determine the fair values of available-for-sale financial assets, forward currency contracts and oil derivatives. Seven Energy warrant’s fair value has been calculated using a Black Scholes option valuation model (note 16). The fair values of long-term interest-bearing loans and borrowings are equivalent to their amortised costs determined as the present value of discounted future cash flows using the effective interest rate. The Company considers that the carrying amounts of trade and other receivables, work-in-progress, trade and other payables, other current and non-current financial assets and liabilities approximate their fair values and are therefore excluded from the above table.

F-198 Notes to the consolidated financial statements continued For the year ended 31 December 2010

33 Risk management and financial instruments continued

Fair value hierarchy The following financial instruments are measured at fair value using the hierarchy below for determination and disclosure of their respective fair values:

Tier 1: Unadjusted quoted prices in active markets for identical financial assets or liabilities

Tier 2: Other valuation techniques where the inputs are based on all observation data (directly or indirectly)

Tier 3: Other valuation techniques where the inputs are based on unobservable market data

Assets measured at fair value Year ended 31 December 2010

Tier 1 Tier 2 2010 US$’000 US$’000 US$’000 Financial assets Available-for-sale financial assets ...... 243 101,251 101,494 Seven Energy warrants ...... — 11,969 11,969 Forward currency contracts-designated as cash flow hedge ...... — 7,961 7,961 Forward currency contracts-undesignated ...... — 1,234 1,234

Financial liabilities Interest-bearing loans and borrowings ...... — 87,661 87,661 Forward currency contracts-designated as cash flow hedge ...... — 8,173 8,173 Forward currency contracts-undesignated ...... — 3,035 3,035 Oil derivative ...... — 1,163 1,163

Year ended 31 December 2009

Tier 1 Tier 2 2009 US$’000 US$’000 US$’000 Financial assets Available-for-sale financial assets ...... — 539 539 Forward currency contracts-designated as cash flow hedge ...... — 26,891 26,891 Forward currency contracts-undesignated ...... — 5,070 5,070

Financial liabilities Interest-bearing loans and borrowings ...... — 117,266 117,266 Oil derivative ...... — 1,813 1,813

34 Events after the reporting date On 31 January 2011, Energy Developments signed an RSC to lead the development of the Berantai field, offshore Peninsular Malaysia for Petronas, the Malaysian national oil company. Petrofac has a 50% interest in the RSC alongside our two local partners who each hold a 25% interest and the joint venture will develop the field and subsequently operate it for seven years after first gas production. As part of the fast track development of the field, the group has committed as at 31 December 2010 to acquire an FPSO vessel which will be jointly owned by Berantai joint venture partners (see note 31 for details).

F-199 Notes to the consolidated financial statements continued For the year ended 31 December 2010

35 Subsidiaries and joint ventures At 31 December 2010, the group had investments in the following subsidiaries and incorporated joint ventures:

Proportion of nominal value of issued shares controlled by the group Name of company Country of incorporation 2010 2009 Trading subsidiaries Petrofac Inc...... USA *100 *100 Petrofac International Ltd ...... Jersey *100 *100 Petrofac Energy Development UK Limited ...... England *100 — Petrofac Energy Developments Limited ...... England — *100 Petrofac Energy Developments International Limited ...... Jersey *100 *100 Petrofac UK Holdings Limited ...... England *100 *100 Petrofac Facilities Management International Limited ...... Jersey *100 *100 Petrofac Services Limited ...... England *100 *100 Petrofac Services Inc...... USA *100 *100 Petrofac Training International Limited ...... Jersey *100 *100 Petroleum Facilities E & C Limited ...... Jersey *100 *100 Petrofac ESOP Trustees Limited ...... Jersey *100 *100 Jermyn Insurance Company Limited ...... Guernsey *100 — Atlantic Resourcing Limited ...... Scotland 100 100 Petrofac Algeria EURL ...... Algeria 100 100 Petrofac Engineering India Private Limited ...... India 100 100 Petrofac Engineering Services India Private Limited ...... India 100 100 Petrofac Engineering Limited ...... England 100 100 Petrofac Offshore Management Limited ...... Jersey 100 100 Petrofac FZE ...... United Arab Emirates 100 100 Petrofac Facilities Management Group Limited ...... Scotland 100 100 Petrofac Facilities Management Limited ...... Scotland 100 100 Petrofac International Nigeria Ltd ...... Nigeria 100 100 Petrofac Pars (PJSC) ...... Iran 100 100 Petrofac Iran (PJSC) ...... Iran 100 100 Plant Asset Management Limited ...... Scotland 100 100 Petrofac Nuigini Limited ...... Papua New Guinea 100 100 PFMAP Sendirian Berhad ...... Malaysia 100 100 Petrofac Caspian Limited ...... Azerbaijan 100 100 Petrofac (Malaysia-PM304) Limited ...... England 100 100 Petrofac Training Group Limited ...... Scotland 100 100 Petrofac Training Holdings Limited ...... Scotland 100 100 Petrofac Training Limited ...... Scotland 100 100 Petrofac Training Inc...... USA 100 100 Petrofac Training (Trinidad) Limited ...... Trinidad 100 100 Monsoon Shipmanagement Limited ...... Jersey 100 100 Petrofac E&C International Limited ...... United Arab Emirates 100 100 Petrofac Saudi Arabia Limited ...... Saudi Arabia 100 100 Petrofac Energy Developments (Ohanet) Jersey Limited ...... Jersey 100 100 Petrofac Energy Developments (Ohanet) LLC ...... USA 100 100 PEDL Limited ...... England — 100 Petrofac (Cyprus) Limited ...... Cyprus 100 100 PKT Technical Services Ltd ...... Russia **50 **50 PKT Training Services Ltd ...... Russia 100 100 Pt PCI Indonesia ...... Indonesia 80 80 Petrofac Training Institute Pte Limited ...... Singapore 100 100 Petrofac Training Sdn Bhd ...... Malaysia 100 100

* Directly held by Petrofac Limited ** Companies consolidated as subsidiaries on the basis of control.

F-200 Notes to the consolidated financial statements continued For the year ended 31 December 2010

35 Subsidiaries and joint ventures continued

Proportion of nominal value of issued shares controlled by the group Name of company Country of incorporation 2010 2009 Trading subsidiaries continued Sakhalin Technical Training Centre ...... Russia 80 80 Petrofac Norge AS ...... Norway 100 100 SPD Group Limited ...... British Virgin Islands 51 51 SPD UK Limited ...... Scotland 51 51 SPDLLC...... United Arab Emirates **25 **25 Petrofac Energy Developments Oceania Limited ...... Cayman Islands — 100 PT. Petrofac IKPT International ...... Indonesia 51 51 Petrofac Kazakhstan Limited ...... England 100 100 Petrofac International (UAE) LLC ...... United Arab Emirates 100 100 Petrofac E&C Oman LLC ...... Oman 100 100 Petrofac International South Africa (Pty) Limited ...... South Africa 100 100 Eclipse Petroleum Technology Limited ...... England 100 100 Eclipse Petroleum Technology Inc ...... United States 100 100 Caltec Limited ...... England 100 100 i Perform Limited ...... Scotland 100 100 Petrofac FPF1 Limited ...... Jersey 100 100 Petrofac Platform Management Services Limited ...... Jersey 100 100 Petrokyrgyzstan Limited ...... Jersey 100 100 Scotvalve Services Limited ...... Scotland 100 — Stephen Gillespie Consultants Limited ...... Scotland 100 — CO2DeepStore Limited ...... Scotland 100 — CO2DeepStore Holdings Limited ...... Jersey 100 — CO2DeepStore (Aspen) Limited ...... England 100 — TNEI Services Limited ...... England 100 — Petrofac E&C Sdn Bhd ...... Malaysia 100 — Petrofac FPSO Holding Limited ...... Jersey 100 — The New Energy Industries Limited ...... England 100 — Petrofac Information Services Private Limited ...... India 100 — Petrofac Solutions & Facilities Support S.R.L ...... Romania 100 —

**Companies consolidated as subsidiaries on the basis of control.

F-201 THE ISSUER Petrofac Limited Ogier House The Esplanade St Helier Jersey JE4 9WG

THE GUARANTORS Petrofac International Ltd Petrofac International (UAE) LLC Ogier House Petrofac House The Esplanade Al Khan Road PO Box 23467 St Helier Sharjah Jersey JE4 9WG United Arab Emirates

JOINT BOOKRUNNERS Barclays Capital Inc. J.P. Morgan Securities LLC 745 Seventh Avenue 383 Madison Avenue New York, New York 10019 New York, NY 10179 United States of America United States of America

Deustche Bank Securities Inc. RBS Securities Inc. 60 Wall Street 600 Washington Boulevard New York, NY 10005 Stamford, CT 06901 United States of America United States of America

LEGAL ADVISERS TO THE ISSUER AND THE GUARANTORS As to Jersey law As to US and English law As to UAE law Carey Olsen Freshfields Bruckhaus Afridi & Angell 47 Esplanade Deringer LLP P.O. Box 9371 St Helier 65 Fleet Street Emirates Towers—Level 35 Jersey JE1 0BD London EC4Y 1HS Sheikh Zayed Road United Kingdom Dubai, United Arab Emirates

LEGAL ADVISERS TO THE INITIAL PURCHASERS As to US and English law Davis Polk & Wardwell London LLP 99 Gresham Street London EC2V 7NG United Kingdom

INDEPENDENT AUDITORS Ernst & Young LLP 1 More London Place London SE1 2AF

FISCAL AGENT, PAYING AGENT, TRANSFER AGENT REGISTRAR Citibank, N.A., London Branch Citigroup Global Markets Deutschland AG Citigroup Centre 60323 Reuterweg 16 Canada Square Frankfurt Am Main Canary Wharf Germany London E14 5LB

IRISH LISTING AGENT Arthur Cox Earlsfort Centre, Earlsfort Terrace Dublin 2 Ireland Printed by RR Donnelley, 523134