Table of Contents

  **UNITED STATES SECURITIES AND EXCHANGE COMMISSION****Washington, D.C. 20549****Form 20-F**   **o** **REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g)    OF THE SECURITIES EXCHANGE ACT OF 1934** **OR** **þ** **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE    SECURITIES EXCHANGE ACT OF 1934**   **For the fiscal year ended December 31, 2005****OR** **o** **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE    SECURITIES EXCHANGE ACT OF 1934**  **For the transition period    from           to****OR** **o** **SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF    THE SECURITIES EXCHANGE ACT OF 1934**  **Date of event requiring this shell company report****Commission File Number: 1-14614****Petroleum Geo-Services ASA***(Exact name of registrant as specified in its charter)***Kingdom of Norway***(Jurisdiction of incorporation or organization)***Strandveien 4, N-1325 Lysaker, Norway***(Address of principal executive offices)***Securities registered or to be registered pursuant toSection 12(b) of the Act:**   **Title of Each Class** **Name of Each Exchange on Which Registered**       American Depositary Shares, each representing     New York Stock Exchange, Inc.    one ordinary share of nominal value NOK 10 per share      Ordinary shares of nominal value NOK 10 per share*     New York Stock Exchange, Inc.**Securities registered or to be registered pursuant toSection 12(g) of the Act:****None****Securities for which there is a reporting obligation pursuantto Section 15(d) of the Act:****None**     Indicate the number of outstanding shares of each of theissuer’s classes of capital or common stock as of the closeof the period covered by the annual report: 60,000,000 ordinaryshares, nominal value NOK 10 per share.     Indicate by check mark if the registrant is a well-knownseasoned issuer, as defined in Rule 405 of the SecuritiesAct.     Yes þ          No o     If this report is an annual or transition report, indicate bycheck mark if the registrant is not required to file reportspursuant to Section 13 or Section 15(d) of theExchangeAct.     Yes o          No þ     Indicate by check mark whether the registrant (1) has filedall reports required to be filed by Section 13 or 15(d) ofthe Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrantwas required to file such reports), and (2) has beensubject to such filing requirements for the past90 days.     Yes þ          No o     Indicate by check mark whether the registrant is a largeaccelerated filer, an accelerated filer, or a non-acceleratedfiler. See definition of “accelerated filer and largeaccelerated filer” inRule 12b-2 of theExchange Act.Large acceleratedfiler þ          Acceleratedfiler o          Non-acceleratedfiler o     Indicate by check mark which financial statement the registranthas elected to follow.Item 17 o          Item 18 þ     If this is an annual report, indicate by check mark whether theregistrant is a shell company (as defined inRule 12b-2 of theExchangeAct).     Yes o          No þ     Indicate by check mark whether the registrant has filed alldocuments and reports required to be filed by Sections 12,13 or 15(d) of the Securities Exchange Act of 1934 subsequent tothe distribution of securities under a plan confirmed by acourt.     Yes þ          No o*     The ordinary shares were registered for technical purposes only,    not involving trading privileges, in accordance with the    requirements of the Securities and Exchange Commission.  

 
**PETROLEUM GEO-SERVICES ASA****ANNUAL REPORT ON FORM 20-F FOR THE****YEAR ENDED DECEMBER 31, 2005****TABLE OF CONTENTS**           **Page**          Petroleum Geo-Services ASA  3      Where You Can Find More Information  3      Forward-Looking Statements  3      Currency Presentations  4 ** PART I**     ITEM 1.      Identity of Directors, Senior Management    and Advisors  5      ITEM 2.      Offer Statistics and Expected Timetable  5      ITEM 3.      Key Information  5      ITEM 4.      Information on the Company  14      ITEM 4A      Unresolved Staff Comments  33      ITEM 5.      Operating and Financial Review and    Prospects  33      ITEM 6.      Directors, Senior Management and    Employees  60      ITEM 7.      Major Shareholders and Related Party    Transactions  67      ITEM 8.      Financial Information  68      ITEM 9.      The Offer and Listing  69      ITEM 10.      Additional Information  71      ITEM 11.      Quantitative and Qualitative Disclosures    About Market Risk  81      ITEM 12.      Description of Securities Other Than Equity    Securities  84  ** PART II**     ITEM 13.      Defaults, Dividend Arrearages and    Delinquencies  84      ITEM 14.      Material Modifications to the Rights of    Security Holders and Use of Proceeds  84      ITEM 15.      Controls and Procedures  84      ITEM 16A.      Audit Committee Financial Expert  85      ITEM 16B.      Code of Ethics  85      ITEM 16C.      Principal Accountant Fees and Services  86      ITEM 16D.      Exemptions from the Listing Standards for    Audit Committees  87      ITEM 16E.      Purchases of Equity Securities by the    Issuer and Affiliated Purchasers  87  **PART III**     ITEM 17.      Financial Statements  87      ITEM 18.      Financial Statements  87      ITEM 19.      Exhibits  87  Articles of Association Contract of Employment - Svein Rennemo Credit Agreement dated December 16, 2005 Certification of CEO Pursuant to Section 302 Certification of CFO Pursuant to Section 302 Certification of CEO & CFO Pursuant to Section 906 Consent of Ernst & Young AS

Table of Contents
**PETROLEUM GEO-SERVICES ASA**     As used in this annual report, we refer to PetroleumGeo-Services ASA, its predecessors and its majority-ownedsubsidiaries as “PGS,” “we,” “us”or “our,” unless the context clearly indicatesotherwise.**WHERE YOU CAN FIND MORE INFORMATION**     We have filed this annual report onForm 20-F with theSecurities and Exchange Commission under the Securities ExchangeAct of 1934. Statements made in this annual report as to thecontents of any agreement or other document referred to are notnecessarily complete. For each such agreement or other documentfiled as an exhibit to this annual report, we urge you to referto the exhibit for a more complete description of the matterinvolved. We are subject to the informational requirements ofthe Exchange Act that apply to foreign private issuers and fileor furnish reports and other information with the SEC. Reportsand other information we file with or furnish to the SEC,including this annual report, may be inspected and copied at thepublic reference facilities of the SEC at 450 Fifth StreetN.W., Washington D.C. 20549. Additionally, information that wefile electronically with the SEC may also be obtained from itsInternet site at *http://www.sec.gov*and our Internet siteat *http://www.pgs.com.* Information contained on orconnected to our website is not incorporated by reference intothis annual report onForm 20-F andshould not be considered part of this report or any other filingthat we make with the SEC.**FORWARD-LOOKING STATEMENTS**     In order to utilize the “Safe Harbor” provisions ofthe United States Private Securities Litigation Reform Act of1995, we are providing the following cautionary statement. Thisannual report, particularly in “Our BusinessPriorities,” “Our Geophysical Services” and“Our Production Segment” in Item 4 and“Outlook; Factors Affecting Our Future OperatingResults” and “Liquidity and Capital Resources” inItem 5, contains forward-looking statements about ourfinancial condition, results of operations, businesses andprospects. These forward-looking statements address matters suchas: •     market conditions, anticipated demand and prices for our    services and for multi-client data that we license, productive    capacity in the markets in which we operate, other competitive    factors, possible expansion, technological developments and    other trends in the businesses in which we operate;  •     business strategies, including geographic areas in which we may    operate from time to time and potential acquisitions and/or    dispositions;  •     maintaining and obtaining contracts for our floating production,    storage and offloading vessels, the estimated productive lives    of the fields served by such vessels and the periods we expect    such vessels to continue to produce such fields;  •     operating regularity and levels of production for our floating    production, storage and offloading vessels;  •     the extent to which our seismic vessels and equipment will be    utilized, including utilization of such vessels to acquire    contract or multi-client seismic data;  •     acquisition of contract and multi-client seismic data,    governmental licensing activity relating to such acquisition and    expected future sales of multi-client seismic data;  •     future capital expenditures, investments in our businesses and    dividends;  •     investments in, and amortization charges for, our multi-client    library;  •     governmental and tax regulations and enforcement;  •     future exposure to currency devaluations or exchange rate    fluctuations, including in particular fluctuations in the value    of the U.S. dollar as compared to the Norwegian kroner and    the British pound; and  •     interest rates.
3

Table of Contents
     These forward-looking statements: •     address activities, events or developments that we expect,    believe, anticipate or estimate will or may occur in the future;  •     are based at least in part on assumptions and analyses that we    have made and that we believe were reasonable under the    circumstances when made; and  •     can be impacted by uncertainties and other factors, many of    which are beyond our control.     Any one of these assumptions, uncertainties or other factors, ora combination of these assumptions, uncertainties or otherfactors, could materially affect our future results ofoperations, financial position, cash flows and whether theforward-looking statements ultimately prove to be accurate.These forward-looking statements are not guarantees of ourfuture performance, and our actual results, financial position,cash flows and future developments may differ materially fromthose projected in the forward-looking statements. Whenconsidering these forward-looking statements, you should keep inmind the risk factors and other cautionary statements disclosedelsewhere in this annual report, including those described under“Key Information — Risk Factors” inItem 3.**CURRENCY PRESENTATIONS**     In this annual report, references to“U.S. dollars,” “dollars” and“$” are to United States dollars; references to“NOK” are to Norwegian kroner; and references to“British pounds” and “£” are to Britishpounds sterling.
4

Table of Contents
**PART I****ITEM 1.*****Identity of Directors, Senior Management and    Advisors***     Not applicable.**ITEM 2.*****Offer Statistics and Expected Timetable***     Not applicable.**ITEM 3.*****Key Information*****Selected Financial Data**     We have presented below, on the basis of U.S. generally acceptedaccounting principles (“U.S. GAAP”), our selectedconsolidated financial data as of December 31, 2005, 2004and 2003 (Successor Company) and as of December 31, 2002and 2001 (Predecessor Company), for the years endedDecember 31, 2005 and 2004 and for the two-month periodended December 31, 2003 (Successor Company) and for theten-month period ended October 31, 2003 and the years endedDecember 31, 2002 and 2001 (Predecessor Company). We havederived the financial data presented below from our auditedfinancial statements including those included in Item 18 ofthis annual report. The financial data presented below excludesour Production Services subsidiary, our Atlantis oil and naturalgas subsidiary and PGS Tigress (UK) Ltd., our softwaresubsidiary, which were sold in 2002 and 2003 and are presentedas discontinued operations in our financial statements for allperiods. You should read the financial data in conjunction with“Operating and Financial Review and Prospects” inItem 5 of this annual report and our consolidated financialstatements and related notes included in Item 18 of thisannual report. The financial data presented below are qualifiedin their entirety by reference to those consolidated financialstatements and related notes.     We operated our business as adebtor-in-possessionunder Chapter 11 of the U.S. Bankruptcy Code fromJuly 29, 2003 until November 5, 2003, when ourreorganization plan became effective and was substantiallyconsummated. Under the plan, our then-existing bank debt andoutstanding senior notes were cancelled in exchange for acombination of new senior notes, a new term loan, new ordinaryshares and the right to receive cash. For additional informationabout our Chapter 11 reorganization, please read“Operating and Financial Review and Prospects —2003 Financial Restructuring” in Item 5 of this annualreport and note 3 of the consolidated financial statementsincluded in Item 18 of this annual report.     We have prepared our post-reorganization consolidated financialstatements in accordance with the American Institute ofCertified Public Accountants Statement ofPosition 90-7,*“Financial Reporting by Entities in Reorganization Underthe Bankruptcy Code,”*orSOP 90-7. Forfinancial reporting purposes, the effects of the completion ofthe reorganization plan and adjustments for fresh-startreporting have been recorded as of October 31, 2003. Underfresh-start reporting, a new entity was deemed created forfinancial reporting purposes, and the carrying values of ourassets were adjusted to their reorganization values, which areequivalent to their estimated fair values. The carrying valuesof our liabilities were also adjusted to their present values.The terms “Predecessor” and “PredecessorCompany” refer to PGS and its subsidiaries for periodsprior to and including October 31, 2003. The terms“Successor” and “Successor Company” refer toPGS and its subsidiaries for periods from and afterNovember 1, 2003. The effects of the completion of thereorganization plan and adjustments for fresh-start reportingrecorded as of October 31, 2003 are Predecessor
5

Table of Contents
Company transactions. All other results of operations onNovember 1, 2003 are Successor Company transactions.                            **Successor Company** **Predecessor Company**         **Two Months** **Ten Months**    **Years Ended December,** **Ended** **Ended** **Years Ended December,**    **December 31,** **October 31,**    **2005** **2004** **2003** **2003** **2002** **2001**               **(In thousands of dollars, except for share data)****STATEMENT OF OPERATIONS DATA:**                            Revenues $1,196,326  $1,129,468  $172,371  $961,864  $1,043,231  $893,230     Operating profit (loss)  335,447   35,683   10,702   9,825   (488,609)  46,798     Debt redemption and refinancing costs  (107,315)  —   —   —   —   —     Reorganization items:                             Gain on debt discharge  —   —   —   1,253,851   —   —      Fresh-start adoption  —   —   —   (532,268)  —   —      Cost of reorganization  —   (3,498)  (3,325)  (52,334)  (3,616)  —     Income (loss) from continuing operations before cumulative    effect of change in accounting principles  112,078   (137,778)  (9,818)  556,938   (809,903)  (140,125)    Net income (loss)  112,578   (134,730)  (9,953)  557,045   (1,174,678)  (172,479)    Basic and diluted income (loss) from continuing operations per    share $1.87  $(2.30) $(0.17) $5.39  $(7.84) $(1.36)    Basic and diluted net income (loss) per share  1,88   (2.25)  (0.17)  5.39   (11.37)  (1.68)    Basic and diluted weighted average shares outstanding(a)  60,000,000   60,000,000   60,000,000   103,345,987   103,345,987   102,768,283 **CASH FLOW DATA:**                            Cash flows provided by operating activities $279,056  $282,372  $62,170  $164,948  $294,609  $110,581     Cash flows provided by (used in) investing activities  10,499   (183,446)  (25,089)  (69,732)  (274,497)  (220,516)    Cash flows provided by (used in) financing activities  (300,953)  (71,283)  (25,807)  (92,896)  (7,636)  64,349     Capital expenditures  90,490   148,372   15,985   42,065   56,735   147,536     Investment in multi-client library  55,667   41,140   9,461   81,142   151,590   174,028      (a)    At our Annual General Meeting on June 8, 2005, our    shareholders approved a three-for-one split of our shares.    Following the split, and as of December 31, 2005, we had    60,000,000 shares issued and outstanding, all of which are    of the same class and have equal voting and dividend rights.    Each share has a par value of NOK 10. All Successor Company    share and per-share information included in this annual report    gives effect to this three-for-one split of our shares.                       **Successor Company** **Predecessor Company**       **December 31,** **December 31,**       **2005** **2004** **2003** **2002** **2001**             **(In thousands of dollars)****BALANCE SHEET DATA:**                        Total assets $1,717,572  $1,852,153  $1,997,360  $2,839,757  $3,962,129     Multi-client library, net  146,171   244,689   408,005   583,859   799,062     Total long-term debt and capital lease obligations  935,339   1,118,346   1,172,147   1,409,134   1,964,888     Guaranteed preferred beneficial interest in PGS junior    subordinated debt securities  —   —   —   142,322   141,000     Common stock  85,714   85,714   85,714   71,089   71,089     Shareholders’ equity (deficit)  329,275   222,907   353,634   (192,254)  979,896 
6

Table of Contents
**Risk Factors**     *You should carefully consider the risks described below. Ifany of the following risks actually occur, our business,financial condition or results of operations could be materiallyadversely affected and the trading price of our securities coulddecline significantly.***Risk Factors Relating to Financial Reporting Matters*****We still have issues regarding our internal control overfinancial reporting. Failure to achieve and maintain effectiveinternal controls could adversely affect both our ability toprovide timely and accurate financial statements and the tradingprices of our securities.***     In September 2003, our independent registered public accountingfirm, Ernst & Young AS (“EY”), identifiedmaterial weaknesses regarding various elements of our system ofinternal controls over financial reporting. A material weaknesscondition exists when significant control deficiencies, or acombination of control deficiencies, are present that results inmore than a remote likelihood that a material misstatement ofthe annual or interim financial statements will not be preventedor detected. In May 2005, in connection with the audit of our2004 financial statements under U.S. GAAP, EY confirmed thecontinuation of such matters that, in the aggregate, theyconsidered to constitute a material weakness.     We believe that the actions we have taken to date to improve ourinternal controls have remediated the previously identifiedmaterial weaknesses. However, our assessment of our internalcontrols for the period relevant to the 2005 financial reportingindicated that two significant control deficiencies remained asof December 31, 2005 regarding the sufficiency of oursupervisory review procedures related to income tax provisionand regarding timely and sufficiently detailed research anddocumentation of certain significant accounting issues. Asignificant deficiency exists when the timeliness and qualitycontrol procedures allow more than a remote likelihood that amisstatement of our annual financial statements that is morethan inconsequential may not be prevented or detected. Ourassessment also identified other control deficiencies.     Beginning with the year ending December 31, 2006,Section 404 of the Sarbanes-Oxley Act will require us toinclude an internal control report of management with our annualreport onForm 20-F. Weexpect to continue to make changes in our internal control overfinancial reporting during our documentation and controlevaluation in preparation for compliance with Section 404of the Sarbanes-Oxley Act. As we implement remaining changes inour internal controls and as we address requirements under theSarbanes-Oxley Act, we may identify additional deficiencies inour system of internal control over financial reporting thatwill require additional remedial efforts.     If we do not maintain effective internal control over financialreporting, we may be unable to process key components of ourresults of operations and financial condition timely andaccurately, investors and rating agencies could lose confidencein our reported financial information and the trading prices ofour securities could be adversely affected.***Our adoption of “fresh start” reporting may make    future financial statements difficult to compare.***     In connection with the November 2003 consummation of ourreorganization plan, we adopted, as of November 1, 2003,fresh start reporting in accordance withSOP 90-7. BecauseSOP 90-7 requiredus to reset our assets and liabilities to then current fairvalues, our financial condition and results of operations afterour reorganization are not comparable to the financial conditionand results of operations reflected in our historical financialstatements for periods prior to November 2003. This may make itdifficult to assess our performance after the reorganizationcompared with our historical performance prior to thereorganization.**Risk Factors Relating to Our Indebtedness and OtherObligations*****We have significant indebtedness and other obligations    that restrict us in various ways.***     We have a relatively high level of indebtedness in relation toour capital structure. As of December 31, 2005, we hadapproximately $980 million of indebtedness and capitalleases outstanding. Our credit facility
7

Table of Contents
and other debt and contractual obligations contain covenants andrestrictions, including provisions that could restrict ourability, among other things, to sell assets; incur additionalindebtedness or issue preferred stock; prepay interest andprincipal on our indebtedness (other than our main creditagreement); pay dividends and distributions or repurchase ourcapital stock; create liens on assets; make investments, loans,guarantees or advances; make acquisitions; engage in mergers orconsolidations; enter into sale and leaseback transactions;engage in transactions with affiliates; amend materialagreements governing our indebtedness; change our business;enter into agreements that restrict dividends from subsidiaries;and enter into speculative financial derivative agreements. Inaddition, our credit facility requires us to comply withspecific financial covenants, including a maximum total leverageratio, a minimum interest coverage ratio and a minimum fixedcharge coverage ratio. Because of this debt and othercontractual obligations: •     we must dedicate some portion of our cash flow from operations    to debt service and other contractual obligations, which reduces    the amount we have available for capital investment, working    capital or other general corporate purposes;  •     we are more vulnerable to adverse developments in general    economic and industry conditions;  •     we may be less flexible in responding to changing market    conditions or in pursuing favorable business opportunities;  •     we may be limited in our ability to borrow additional    funds; and  •     we may be at a competitive disadvantage compared to our    competitors that have less debt.***Our ability to obtain additional financing or to refinance    our indebtedness could be restricted.***     As of March 2006, our long-term secured indebtedness carried anon-investment grade rating from both Moody’s InvestorsService, Inc. rating agency (Ba3) and Standard &Poor’s Ratings Services, a division of The McGraw-HillCompanies, Inc. (B+). As long as we have a non-investment gradecredit rating, our access to the debt capital markets will berestricted to the non-investment grade sector. Such a situationcould increase our borrowing costs or restrict our ability toobtain additional financing or to refinance our existingindebtedness, or to do so on satisfactory terms.**Risk Factors Relating to Our Business Operations Generally*****We have experienced substantial losses in the past and may    do so in the future.***     For the year ended December 31, 2004, we suffered a netloss of $135 million. We may incur net losses, as well asoperating losses, in the future.***Our business could be adversely affected if demand for our    services from oil and natural gas companies decreases.***     Our geophysical and offshore production businesses dependsubstantially upon exploration, development and productionspending by oil and natural gas companies. Capital expenditures,and in particular exploration and development expenditures, byoil and natural gas companies have tended in the past to followthe prices of oil and natural gas, which have fluctuated widelyin recent years. Lower oil and natural gas prices, actual orprojected, and other factors, including mergers of oil andnatural gas companies, may reduce the level of thoseexpenditures, which could adversely affect our businesses.***We could incur operating losses if we cannot keep our    vessels and other equipment utilized at high levels.***     Our businesses are capital intensive, and we make significantinvestments in vessels and in processing, seismic and otherequipment. We also incur relatively high fixed costs in ouroperations. As a result, if we cannot keep our vessels and otherequipment utilized at relatively high levels, due to reduceddemand, weather interruptions, equipment failure, technicaldifficulties, labor unrest or other causes, we could incursignificant operating losses.
8

Table of Contents
***Our future revenues may fluctuate significantly from    period to period.***     Our future revenues may fluctuate significantly from quarter toquarter and from year to year as a result of various factorsincluding the following: •     fluctuating oil and natural gas prices, which may impact    customer demand for our services;  •     different levels of activity planned by our customers;  •     the timing of offshore lease sales and licensing rounds and the    effect of such timing on the demand for seismic data and    geophysical services;  •     the timing of award and commencement of significant contracts    for offshore production services and geophysical data    acquisition services;  •     weather and other seasonal factors; and  •     seasonality in the sales of geophysical data from our    multi-client data library.***Our technology could be rendered obsolete since    technological changes and new products and services are    regularly introduced to our markets, and we may not be able to    develop and produce competitive products and services on a    cost-effective and timely basis.***     We will be required to invest substantial capital to maintaincompetitive technologies. Technology changes rapidly, and newand enhanced products and services are frequently introduced inour markets, particularly in the geophysical services andseismic data processing business. Our success depends to asignificant extent on our ability to develop and produce new andenhanced products and services on a cost-effective and timelybasis in accordance with industry demands. While we commitresources to research and development, we may encounter resourceconstraints or technical or other difficulties that could delayintroduction of new and enhanced products and services in thefuture. In addition, continuing development of new products andservices inherently carries the risk of obsolescence of olderproducts and services. New and enhanced products and services,if introduced, may not gain market acceptance or may beadversely affected by technological changes.***Unpredictable changes in governmental regulations could    increase our operating costs and reduce demand for our    services.***     Our operations are affected by a variety of laws andregulations, including those relating to: •     permit or license requirements for geophysical activities and    for oil and natural gas exploration, development and production    activities;  •     exports and imports;  •     taxes;  •     occupational health and safety; and  •     the protection of the environment.     We and our customers are required to invest financial andmanagerial resources to comply with these laws and regulations.Because these laws and regulations and our business change fromtime to time, we cannot predict the future costs of complyingwith these laws and regulations, and our expenditures couldincrease materially in the future. Modification of existing lawsor regulations or adoption of new laws or regulations limitingexploration or production activities by oil and natural gascompanies or imposing more stringent restrictions on geophysicalor hydrocarbon production-related operations could adverselyaffect us by increasing our operating costs and/or reducing thedemand for our services.
9

Table of Contents
***Because we conduct a substantial amount of international    operations, we have exposure to those risks inherent in doing    business abroad.***     A significant portion of our revenue is derived from operationsoutside the United States and Norway. These operations aresubject in varying degrees to risks inherent in doing businessabroad, including risks of war, terrorist activities, political,civil or labor disturbances, border disputes and embargoes. Ouroperations are also subject to various risks related togovernment activities, including: •     the disruption of operations from labor and political    disturbances;  •     the possibility of unfavorable changes in tax or other laws;  •     partial or total expropriation;  •     restrictions on currency repatriation or the imposition of new    laws or regulations that preclude or restrict the conversion and    free flow of currencies;  •     the imposition of new laws or regulations that have the effect    of restricting operations or increasing the cost of    operations; and  •     the disruption or delay of licensing or leasing activities.***We are subject to hazards relating to our geophysical and    production businesses.***     Our seismic data acquisition and offshore production servicesoften take place under extreme weather and other hazardousconditions. In particular, a substantial portion of ouroperations are subject to perils that are customary for marineoperations, including capsizing, grounding, collision,interruption and damage or loss from severe weather conditions,fire, explosions and environmental contamination from spillage.Any of these risks, whether in our marine or onshore operations,could result in damage to or destruction of vessels orequipment, personal injury and property damage, suspension ofoperations or environmental damage. In addition, our operationsinvolve risks of a technical and operational nature due to thecomplex systems that we utilize. If any of these events occur,our business could be interrupted and we could incur significantliabilities. In addition, many similar risks may result incurtailment or cancellation of, or delays in, exploration andproduction activities of our customers, which could in turnadversely impact our operations.***Because we do not have insurance with third party carriers    to cover some operating risks, our results of operations could    be adversely affected if one or more of those risks    occurred.***     We do not carry full insurance for all of our operating risks.Although we generally attempt to carry insurance against thedestruction of or damage to our seismic and floating production,storage and offloading vessels and equipment in amounts that weconsider adequate, such insurance coverage is subject to variousexclusions. In addition, we may not be able to maintain adequateinsurance for our vessels and equipment in the future or do soat rates that we consider reasonable. We do not maintaininsurance to protect against loss of revenues caused by businessinterruptions, except for limited protection with respect to theFPSOs *Petrojarl Foinaven*and *Petrojarl Varg.****Because we generate revenue and incur expenses in various    currencies, exchange rate fluctuations and devaluations could    have a material impact on our results of operations.***     Currency exchange rate fluctuations and currency devaluationscould have a material impact on our results of operations fromtime to time. Historically, most of our revenue and operatingexpenses have been generated in U.S. dollars, NOK andBritish pounds, but we predominantly sell our products andservices in U.S. dollars while some portion of ouroperating expenses are incurred in NOK and British pounds. Adepreciation in the U.S. dollar compared to these othercurrencies adversely affects our reported results of operationssince expenses denominated in NOK or British pounds areconverted into U.S. dollars, our reporting currency, at anincreased value. Although we periodically undertake limitedhedging activities in an attempt to reduce some currencyfluctuation risks, these activities do not provide completeprotection from currency-related losses. In addition, in somecircumstances our hedging activities can require us to make cash
10

Table of Contents
outlays. Finally, the amount of currency hedging transactions weare able to enter into may be limited because of our having anon-investment grade credit rating.***We are subject to intense competition that could limit our    ability to maintain or increase our market share and to maintain    our prices at profitable levels.***     Most of our geophysical and offshore production contracts areobtained through a competitive bidding process. While no singlecompany competes with us in all of our business segments, we aresubject to intense competition from large, internationalcompanies and smaller, local companies in each of ourbusinesses. Some of our competitors may have greater financialand other resources than us and may be better positioned towithstand and adjust more quickly to volatile market conditionsand changes in government regulations. We also face competitionfrom new low-cost competitors in various geographic areas,particularly in the onshore seismic market.***Our strategy of pursuing selective growth opportunities    may be unsuccessful if we incorrectly predict operating results    for acquired assets or businesses, are unable to identify and    complete future acquisitions and integrate acquired assets or    businesses or are unable to raise financing for acquisitions on    acceptable terms.***     The acquisition of assets or businesses on a selective basis orthe making of strategic investments on a selective basis incompanies or ventures that are complementary to our business isa component of our business strategy. We believe that attractiveacquisition and strategic investment opportunities may arisefrom time to time, and any such acquisition or investment couldbe significant. At any given time, discussions with one or morepotential sellers or possible business partners may be atdifferent stages. However, any such discussions may not resultin the consummation of an acquisition transaction or strategicinvestment, and we may not be able to identify or complete anyacquisitions or investments. Furthermore, we cannot predict theeffect, if any, that any announcement or consummation of anacquisition or strategic investment transaction would have onthe trading prices of our securities.***Our results of operations depend in part upon our ability    to establish and protect our proprietary technology.***     We rely on a combination of patents, trademarks, copyrights andtrade secret laws to establish and protect our proprietarytechnology. We endeavor to obtain patents on our technology inNorway, the United States and the United Kingdom and in otherjurisdictions that we consider important to our business. Inaddition, we enter into confidentiality and license agreementswith our employees, and with consultants and companies from whomwe acquire technology, and with others who have access to ourproprietary technology. However, we do not patent all of ourproprietary technology, and enforcement of proprietarytechnology rights may be difficult in some jurisdictions.Accordingly, the procedures we have taken to protect ourproprietary rights may not be adequate to deter themisappropriation of our proprietary technology in all situations.***We depend on attracting and retaining qualified employees    to develop our business.***     The development of our business depends in large part upon ourability to attract and retain highly skilled and qualifiedpersonnel with the technical expertise required for ourbusiness. Our results of operations and financial conditioncould be adversely affected by increased labor costs or by anyinability of our company in the future to hire, train and retaina sufficient number of qualified employees.**Risk Factors Relating Primarily to Our Geophysical Business,Both Marine Geophysical and Onshore*****We invest significant amounts of money in acquiring and    processing seismic data for our multi-client data library    without being certain about how much of the data we will be able    to sell or when and at what price we will be able to sell the    data.***     We invest significant amounts in acquiring and processingseismic data that we own, which we call multi-client data. Ourfuture multi-client data sales, including the timing of suchsales, are uncertain and depend on
11

Table of Contents
a variety of factors, many of which are beyond our control. Bymaking such investments, we assume the risk that: •     we may not fully recover the costs of the data through future    sales; and  •     the value of our multi-client data could be adversely affected    by, among other things, any adverse change in the general    prospects for oil and natural gas exploration, development and    production activities in the areas where we acquire multi-client    data, by technological or regulatory changes and by other    industry or general economic developments.     In particular, we own a significant amount of multi-client dataoffshore Brazil. As of December 31, 2005, the carryingvalue of our multi-client data offshore Brazil was$87.9 million. A further delay of sales in this regioncould have an adverse impact on our multi-client data sales.     In the past, we have incurred substantial impairment chargesrelated to our multi-client data.***The amounts we amortize from our multi-client data library    each period may fluctuate significantly, and these fluctuations    can have a significant effect on our results of    operations.***     The manner in which we account for our multi-client data libraryhas a significant effect on our results of operations. Weamortize the capitalized cost of our multi-client data librarybased principally on the relationship of actual data sales forthe relevant data to our estimates of total, including future,sales of data. Our sales estimates are inherently imprecise andmay vary from period to period depending upon marketdevelopments and our expectations. Changes in the amounts andtiming of data sales may result in impairment charges or changesin our amortization expense, which will affect our results ofoperations.     Substantial changes in amortization rates can have a significanteffect on our results of operations.***We perform a portion of our contract seismic work under    turnkey arrangements. If we bid too low on these contracts, we    could incur losses on projects and experience reduced    profitability.***     Many of our contracts for seismic data acquisition are turnkeycontracts, where our work is delivered at a predetermined andfixed price. In submitting a bid on a turnkey contract, weestimate our costs associated with the project. However, ouractual costs can vary from our estimated costs because ofchanges in assumed operating conditions (including weather,fishing activity, interference from other seismic vessels andother operating disturbances), exchange rates and equipmentproductivity, among others. As a result, we may experiencereduced profitability or losses on projects if our bids onturnkey contracts are too low and/or actual costs exceedestimated costs.***Our profitability could be negatively impacted by excess    capacity in the geophysical industry.***     When demand for marine seismic services increases, industryparticipants have previously responded by increasing capacity bybuilding new seismic vessels or converting existing vessels foruse in marine seismic operations. A significant increase in theindustry’s capacity could have an adverse effect on thepricing of our services and our profitability.**Risk Factors Relating Primarily to Our Production Business*****Our operating results could suffer as a result of risks    arising from our floating production, storage and offloading    contracts.***     Our floating production, storage and offloading contractsinvolve various risks, including risks of: •     failure to operate at high levels on a sustained basis for    technical reasons, including operational difficulties that    require modification of vessels or equipment, or due to strikes,    employee lockouts or other labor unrest;  •     reduced revenues to the extent that production decreases since    all of our contracts contain a volume dependent tariff element;
12

Table of Contents
 •     contract termination prior to the scheduled or anticipated    expiration date for the contracts;  •     failure to redeploy vessels following expiration or termination    of long-term contracts; and  •     failure of the underlying reservoir and/or the prevailing market    prices for oil and natural gas to allow production of the    expected amounts of oil and natural gas under contracts where    our compensation depends to a significant degree on the amount    of oil and natural gas produced.**Risk Factors Relating to Our Proposed SeparationTransaction*****Our proposed separation transaction could result in    reduced liquidity, share price or market capitalization.***     On March 27, 2006, our Board of Directors authorizedproceeding with a demerger plan under Norwegian law to separateour geophysical and production business and calling anextraordinary general meeting of our shareholders to vote on thetransaction, to be held on April 28, 2006. If thetransaction is approved by our shareholders and completed, ourshares would be split into shares of two independently listedcompanies. There has been no prior market for shares of ourproduction business on a stand-alone basis. Although our shareshave been listed on the Oslo Stock Exchange and New York StockExchange, after the separation, our shares will represent sharesin a smaller company. Moreover, subsequent to the separation, wewill become a more specialized company, comprised exclusively ofour geophysical business. As a result, our current shareholdersmay decide to sell shares after the separation if they considerus no longer appropriate for their investment portfolios. Thesefacts could have a material adverse effect on the liquidity andshare price of each of the new companies compared to our sharesat present. The combined trading prices of shares after ourproposed separation may not be equal to or greater than thetrading price of our shares prior to the separation. For moreinformation relating to our possible separation, see“Information on the Company — Proposed Separationof the Geophysical and Production Businesses” inItem 4 of this annual report. In addition, for moreinformation about important factors relating to our proposedseparation transaction, please refer to the disclosure documentthat we will make available to our shareholders in connectionwith the proposed separation.***Consummation of our proposed separation transaction is    subject to the satisfaction or waiver of a number of conditions,    and a separation may not be completed as currently    contemplated.***     Completion of our proposed separation transaction is subject tothe satisfaction or waiver of a number of conditions, including: •     the receipt or waiver of all consents required in respect of the    proposed separation;  •     notice from the Oslo Stock Exchange that our production business    will be accepted for listing immediately after the separation    has been registered with the Norwegian Register of Business    Enterprises and the new shares of our production business have    been registered with the Norwegian Registry of Securities;  •     evidence of the ability of our production business to satisfy    its indebtedness;  •     expiration of the deadline under Norwegian law for creditor    objections and satisfaction of any creditor objections; and  •     approval of the proposed separation by our shareholders.     These conditions may not be satisfied or waived, in which casethe proposed separation transaction would not be consummated.***Our proposed separation transaction could have adverse taxconsequences to us and the holders of our shares.***     Our proposed separation transaction may have adverse taxconsequences to us in certain jurisdictions. In addition,holders of our shares in certain jurisdictions may be subject totaxation as a result of the separation. For a more completediscussion of the tax aspects of our proposed separationtransaction, please refer to the disclosure document that wewill make available to our shareholders in connection with theproposed separation.
13

Table of Contents
**Other Risk Factors*****We are a multinational organization faced with    increasingly complex tax issues in many jurisdictions, and we    could be obligated to pay additional taxes in various    jurisdictions.***     As a multinational organization, we are subject to taxation inmany jurisdictions around the world with increasingly complextax laws. The amounts of taxes we pay in these jurisdictionscould increase substantially as a result of changes in theselaws or their interpretations by the relevant taxingauthorities, which could have a material adverse effect on ourliquidity and results of operations. In addition, thoseauthorities could review our tax returns and impose additionaltaxes and penalties, which could be material. We have identifiedissues in several jurisdictions that could eventually make usliable to pay material amounts in taxes relating to prior years.We also have an issue relating to the rate at which capitalallowances can be claimed under the UK lease for *PetrojarlFoinaven*. Additional issues that we are not currently awareof may be identified in the future.***Because we are a foreign company and many of our directors    and executive officers are not residents of the United States,    you may have difficulty suing us and obtaining or enforcing    judgments against us.***     We are incorporated in the Kingdom of Norway, and substantiallyall of our current directors and executive officers resideoutside the United States. All or a substantial portion of theassets of these persons and our company are located outside theUnited States. As a result, you may have difficulty: •     suing us or our directors and executive officers in the United    States;  •     obtaining a judgment in the Kingdom of Norway in an original    action based solely on United States federal securities    laws; and  •     enforcing in the Kingdom of Norway judgments obtained in the    United States courts that are based upon the civil liability    provisions of the United States federal securities laws.***We could be adversely affected by violations of applicable    anti-corruption laws.***     We and our affiliated entities conduct business in countriesknown to experience government corruption. We are committed todoing business in accordance with our code of conduct, but thereis a risk that we, our affiliated entities or our or theirrespective officers, directors, employees and agents may takeaction in violation of applicable anti-corruption laws,including the U.S. Foreign Corrupt Practices Act of 1977.Any such violations could result in substantial civil and/orcriminal penalties and might adversely affect our business,results of operations or financial condition.**ITEM 4.*****Information on the Company*****History and Development of the Company*****Organization***     Petroleum Geo-Services ASA is a public limited liability companyestablished under the laws of the Kingdom of Norway in 1991. Weare organized as a holding company that owns subsidiarycompanies. Our subsidiary companies conduct substantially all ofour business. Unless we inform you otherwise or the contextindicates otherwise, references to us in this annual report areto Petroleum Geo-Services ASA, its predecessors and itsmajority-owned subsidiaries. We maintain our headquarters andexecutive offices at Lysaker, Norway (Strandveien 4,N-1325, telephone: +47-67-52-64-00). Our registration number inthe Norwegian Company Registry is 916235291. Our agent in theUnited States is CT Corporation System, 1633 Broadway, New York,New York 10019.***Who We Are***     We are a technologically focused oilfield service companyprincipally involved in providing geophysical services worldwideand providing floating production services in the North Sea.Globally, we provide a broad
14

Table of Contents
range of geophysical and reservoir services, including seismicdata acquisition, processing and interpretation and fieldevaluation. In the North Sea, we own and operate four harshenvironment floating production, storage and offloading(“FPSO”) units.     In 2005 we managed our business in three segments as follows: • *Marine Geophysical*, which consists of both streamer and    seafloor seismic data acquisition, marine multi-client library    and data processing;  • *Onshore*, which consists of all seismic operations on land    and in very shallow water and transition zones, including our    onshore multi-client library; and  • *Production*, which owns and operates four harsh    environment FPSO units in the North Sea.     We manage our Marine Geophysical segment from Lysaker, Norway,our Onshore segment from Houston, Texas, and our Productionsegment from Trondheim, Norway.     On March 1, 2005 we sold Pertra AS, a small oil and naturalgas company that we managed as a separate segment before thesale, to Talisman Energy (UK) Ltd. (“Talisman”)as described in more detail below. Pertra was included in ourreported numbers through February 2005. Pertra owned 70% of andwas operator for Production License 038 (“PL038”) onthe Norwegian Continental Shelf (“NCS”) and also ownedparticipating interests in six additional NCS licenses withoutproduction. Pertra has been renamed Talisman Production Norge AS.     We also announced in September 2005 that we would convert our 4Cocean bottom crew operation, including the vessels *OceanExplorer*and *Falcon Explorer*, to towed streamervessels. The conversion was concluded in February 2006.     On March 27, 2006, our Board of Directors authorizedproceeding with a demerger plan under Norwegian law to separateour geophysical and production businesses and calling anextraordinary general meeting of our shareholders to vote on thetransaction, to be held on April 28, 2006. If thetransaction is approved by our shareholders and completed, ourshares would be split into shares of two independently listedcompanies. For more information relating to our possibleseparation, see “Proposed Separation of the Geophysical andProduction Businesses” below.***Historical Development***     The primary milestones in our historical development include thefollowing: • *January 1991:* Company established with the merger of    Geoteam a.s. and Nopec a.s.  • *August 1992:* Company ordinary shares listed on Oslo Stock    Exchange  • *May 1993:* Initial public offering and listing in    U.S. on NASDAQ  • *1995-1999:* Construction and deployment of six Ramform    design 3D seismic vessels  • *April 1997:* Listing of our ADSs on the New York Stock    Exchange  • *May 1998:* Acquisition of Golar-Nor (*Petrojarl I*and *Petrojarl Foinaven*)  • *October 1998:* Delivery of *Ramform Banff*  • *July 1999:* Acquisition of FPSO *Varg*(renamed    *Petrojarl Varg*)  • *March 2001:* Sale of data management business and related    software to Landmark Graphics Corporation, a subsidiary of    Halliburton, and resumption of oil production by the re-tooled    *Ramform Banff*
15

Table of Contents
 • *August 2002:* Acquisition of 70% ownership in, and    operatorship of, PL 038 on NCS of the North Sea (including Varg    field)  • *August-November 2002:* Replacement of various members of    senior management, including the Chairman of the Board and Chief    Executive Officer and the Chief Financial Officer, with a new    non-executive Chairman of the Board, a new Chief Executive    Officer and a new Chief Financial Officer  • *February 2003:* Sale of Atlantis subsidiary to Sinochem  • *February 2003:* Delisting of ADSs from the New York Stock    Exchange and quotations for ADSs available through Pink Sheets  • *July 2003:* Filing under Chapter 11 of    U.S. Bankruptcy Code  • *November 2003:* Emergence from Chapter 11    proceedings, reorganization plan becomes effective and new Board    of Directors takes office  • *December 2004:* Re-listing of our ADSs on the New York    Stock Exchange following filing of    Form 20-F for 2003    fiscal year  • *March 2005:* Sale of oil and natural gas subsidiary Pertra    to Talisman  • *November 2005:* Announcement of intention to explore    possible separation of our geophysical and production businesses    into two independently listed companies  • *December 2005:* Completion of refinancing of    $746 million of 10% senior notes and $110 million    credit facility with a $1 billion senior secured credit    facility  • *February 2006:* Announced a proposed joint venture with    Teekay Shipping Corporation to develop new FPSO projects  • *March 2006:* Announcement of a project to build a new and    enhanced Ramform seismic vessel  • *March 2006:* Authorization by our Board of Directors to    demerge our production business, to be operated under the name    “Petrojarl”**2005 Developments**     Our primary business achievements in 2005 were: •     we improved our strong safety performance  •     we achieved a strong full year cash flow and a significant debt    reduction  •     we significantly improved our marine seismic contract operating    profit margins  •     we increased marine multi-client late sales by 8% compared to    2004, despite three years of low multi-client investments  •     we sold our oil and gas subsidiary Pertra  •     we repaid from available cash or refinanced the majority of our    debt to provide greater operating flexibility and lower    borrowing costs     In addition, during the first three months of 2006 we have: •     acquired the shuttle tanker *Rita Knutsen*for a possible    FPSO conversion  •     announced a proposed joint venture with Teekay to develop new    FPSO projects  •     announced a project to build a new and enhanced Ramform seismic    vessel for delivery in early 2008  •     decided to propose to our shareholders a demerger of our    production business, to be operated under the name    “Petrojarl”
16

Table of Contents
**Proposed Separation of Our Geophysical and ProductionBusinesses**     We currently conduct our business in two primary business areas: •     our geophysical business, which includes our Marine Geophysical    and Onshore operations, and  •     our production business.     Historically, the geophysical business and the productionbusiness have been organized and operated as separate businesses.     On March 27, 2006, our Board of Directors authorizedproceeding with a demerger plan under Norwegian law to separateour geophysical and production businesses into two independentlylisted companies and calling an extraordinary general meeting ofour shareholders to vote on the transaction, to be held onApril 28, 2006.     Under the proposed demerger, our subsidiary companies thatconduct the production business, and the assets, rights andliabilities related to the production business, will betransferred to a wholly owned subsidiary named Petrojarl ASA.Our subsidiary companies that conduct the geophysical business,and the assets, rights and liabilities related to thegeophysical business, will be retained under PetroleumGeo-Services ASA.     When the separation is completed, each holder of our ordinaryshares will receive one ordinary share of Petrojarl for each ofour shares held and each holder of American Depositary Shares(“PGS ADSs”) representing our ordinary shares willreceive one newly issued American Depositary Share representingan ordinary share in Petrojarl (“Petrojarl ADSs”) foreach PGS ADS held. We intend to apply for a listing of theordinary shares of Petrojarl ASA on the Oslo Stock Exchange. Wedo not intend to list the Petrojarl ordinary shares or PetrojarlADSs in the U.S.     Immediately after consummation of the demerger, PGS ASA wouldhold shares in Petrojarl representing a 19.99% interest inPetrojarl and the Petrojarl shares issued to the holders of ourshares and the PGS ADSs would represent the remaining 80.01%interest in Petrojarl. Subject to prevailing market conditionsand other factors, PGS ASA expects to sell the shares inPetrojarl in a public offering in conjunction with theconsummation of the separation and demerger.     If the demerger plan is approved by the requisite two-third voteof our shareholders and the conditions precedent to consummationof the demerger are satisfied, or where applicable waived, wecurrently expect the demerger to be consummated in July 2006.     After completion of the demerger, PGS ASA will continue ourgeophysical business and hold its assets, rights and liabilities.     Upon consummation of the separation, we expect that Petrojarlwill have a new $425 million five year borrowing facilityand will initially borrow $325 million under the facility.The proceeds from the initial borrowing, together with anyproceeds from any sale of all or any part of the Petrojarlshares retained by PGS ASA, will be used by PGS ASA forrepayment of existing debt or other purposes. As part of theseparation transaction, Petrojarl will receive cash and cashequivalents of approximately $50 million and will haveapproximately $275 million of net interest-bearing debtimmediately following consummation of the separation.     In connection with the demerger, we have entered into otheragreements, subject to final documentation, either as part ofthe proposed demerger plan or otherwise, to facilitate thedemerger. For our UK leases on three of our Ramform seismicvessels and the production equipment for the *RamformBanff*, we have entered into agreements, subject to finaldocumentation, with the lessors providing for certain optionswith respect to the termination of the leases at reducedtermination fees, subject to completion of the demerger. If allof such leases were terminated, we would be required to paytermination fees of up to 13 million British pounds(approximately $23 million). Upon termination, we and, inthe case of *Ramform Banff,* Petrojarl would become theowner of the assets and avoid any additional rental paymentsrelating to these UK leases. In addition, we have reached anagreement, subject to final documentation, with the operator of*Petrojarl Foinaven*to provide the benefit of financialcovenants that would apply to Petrojarl following the demerger
17

Table of Contents
and to make other amendments to the existing contractualarrangements, in each case subject to completion of the demergerand certain other conditions. We will provide more detailedinformation related to the separation and demerger, as well asthe other agreements, in a shareholder information statementprior to the extraordinary general meeting of our shareholderscalled to consider the separation and demerger, which we expectto occur in April 2006.**Sales of Atlantis and Tigress Subsidiaries**     In February 2003, we sold our Atlantis oil and natural gassubsidiary to China National Chemicals Import and ExportCorporation for a combination of $48.6 million in cash, thereimbursement of $10.6 million of expenditures and theright to receive additional future payments of up to$25.0 million if certain contingent events occur. The saleagreement was amended in June 2005 and now provides that we mayreceive a maximum of $10.0 million if certain contingentevents occur. In March 2006, we received confirmation of theoccurrence of certain of these events that entitle us to receive$6 million, of which $3 million was received inMarch 2006.     In December 2003, we sold our software subsidiary, PGS Tigress(UK) Ltd., for a deferred compensation payable in 2004 and 2007of $1.8 million in the aggregate, for which payments werereceived in December 2005 and 2004. We may also receiveadditional contingent proceeds based on performance of thecompany through 2006.**Sale of Our Oil and Natural Gas Subsidiary Pertra**     On March 1, 2005, we sold our wholly owned subsidiaryPertra AS to Talisman for an initial sales price ofapproximately $155 million, which resulted in a gain of$149.8 million, including the $2.5 million received togrant an option to make certain amendments to the charter andoperating agreement for the *Petrojarl Varg*as describedbelow.     As a part of the agreement with Talisman, we are entitled to anadditional sales consideration equal to the value, on a postpetroleum tax basis, of 50% of the relevant revenues from theVarg field in excess of $240 million for each of the yearsended December 31, 2005 and 2006. In January 2006 wereceived $8.1 million, representing the 2005 portion of thecontingent consideration, and recognized that amount in 2005 asan additional gain from the sale.     We also granted an option enabling Talisman to change thetermination clause with respect to *Petrojarl Varg*. Theoption expired on February 1, 2006, without beingexercised. We are entitled to terminate the agreement if theaverage normal production from the Varg field falls below15,700 barrels per day. Based on the current productionprofile of the Varg field, *Petrojarl Varg* could becomeavailable for redeployment on a new field in 2008.     The table below shows revenues and operating profit (loss) as ifPertra had not been included in our consolidated results for theperiods presented.           **Years Ended**  **December 31,**     **2005** **2004**       **Unaudited** **Unaudited**  **(In millions of dollars)**    Revenues $1,170.1  $1,017.5     Operating profit  177.7   9.5      For additional information about our acquisitions anddispositions, please read note 24 of the notes to ourconsolidated financial statements in Item 18 of this annualreport.**Our Business Priorities**     Following the sale of Pertra, significant debt reduction and asuccessful refinancing, we intend to create value for ourshareholders through establishing our geophysical and productionbusinesses as separate and
18

Table of Contents
focused companies. On March 27, 2006, our Board ofDirectors authorized proceeding with a demerger plan underNorwegian law to separate our geophysical and productionbusinesses and calling an extraordinary general meeting of ourshareholders to vote on the transaction, to be held onApril 28, 2006. If the transaction is approved by ourshareholders and completed, we will continue the geophysicalbusiness in our company, while the production business will bediscontinued as part of our company and continued through theseparate company Petrojarl ASA which will be listed the OsloStock Exchange. Please see “Proposed Separation of theGeophysical and Production Businesses” above for moreinformation on the proposed separation. Our main priority in theshort term is to successfully complete the separation andposition both companies for growth.     We intend to continue our focus on health, safety andenvironment (“HSE”) performance and strengtheninginternal controls, corporate governance and human resourcecapabilities.     Within Marine Geophysical, we intend to maintain our emphasis onhigher acquisition productivity and regularity in our operationsand in customer delivery. We will seek to enhance theproductivity advantage of our Ramform vessels through increasingthe streamer count. We will seek to expand our market share inthe data processing business and invest prudently in technology,equipment and multi-client seismic data.     Within Onshore, we aim to utilize fully our present equipment,while pursuing a broader, but selective geographical marketexposure.     Within our Production segment, we intend to maintain ourposition as a leader in harsh environment operations, whileseeking growth opportunities in and outside the North Sea,primarily through the planned Teekay Petrojarl Offshore jointventure.**Our Geophysical Services*****Overview***     We manage our geophysical services through two segments: • *Marine Geophysical*, which consists of streamer seismic    data acquisition, marine multi-client library and data    processing; and  • *Onshore*, which consists of all seismic operations on land    and in very shallow water and transition zones, including our    onshore multi-client library.     Our geophysical services business is one of the major globalparticipants in the acquisition of marine three-dimensional (3D)seismic data. This business acquires, processes, interprets,markets and sells seismic data worldwide that is used by oil andnatural gas companies to help them find oil and natural gas andto determine the size and structure of known oil and natural gasreservoirs. In our seismic projects, we are involved in planningthe seismic surveys and acquiring and processing the seismicdata. Oil and natural gas companies use this information inevaluating whether to acquire new leases or licenses in areaswith potential accumulations of oil and natural gas, inselecting drilling locations, in modeling oil and natural gasreservoir areas and in managing producing reservoirs. Oil andnatural gas companies use 4D or time lapse surveys, which aresurveys produced by the repetition of identical 3D surveys overtime, to assist in their evaluation of subsurface geophysicalconditions that change over time due to the depletion andproduction of reservoir fluids. This evaluation provides formore efficient production of the reservoir and the possibleextension of the reservoir’s useful life. We use our HighDensity 3D —HD3Dsm —technology to acquire 3D data with higher trace densities,giving improved resolution of the subsurface and higher qualityimages of the reservoirs.     We acquire seismic data both on an exclusive contract basis forour customers and on our own behalf as multi-client data forlicensing from time to time to multiple customers on anon-exclusive basis. In some of our projects, we share interestsin the revenue from the sales of the multi-client data withthird parties. During 2005, we used our active seismic vesselacquisition capacity, measured by time, approximately 91% toacquire contract data and approximately 9% to acquiremulti-client data.
19

Table of Contents
     During 2005, we: •     continued our strong HSE performance;  •     continued our focus on contract seismic;  •     increased our investments in multi-client seismic while at the    same time achieved a pre-funding ratio of 101% of cash    investments in the multi-client library;  •     increased the level of our late-sales of multi-client data,    despite three years of relatively low investments in    multi-client data;  •     increased significantly our contract order backlog in Marine    Geophysical; and  •     strengthened our Onshore operations with the commencement of new    significant contracts in Africa.***Our Strategies for Geophysical Services***     Our principal strategies for our geophysical services include: •     capitalizing on our strong cost position and operating    performance through the Ramform concept;  •     increasing our operating margins on existing acquisition    capacity by: •     reducing steaming and downtime in Marine Geophysical,  •     increasing our focus on survey project planning and execution,  •     entering selected new geographic areas in Onshore,  •     focusing our work where premium pricing is available,  •     selectively increasing our streamer count, and  •     investing in more effective acquisition capacity; •     maximizing the value of our multi-client data library by: •     increasing our investments in our multi-client library with    strong emphasis on prospectivity and high pre-funding,  •     strengthening our emphasis on the target selection process and    assessment of prospectivity,  •     enhancing our existing library through reprocessing, and  •     re-entering the Gulf of Mexico with selective investments; •     capturing the full potential in our data processing centers and    increasing our market share, especially in high-end processing;  •     commercializing and investing in new technology and equipment,    including new streamers, to increase productivity on our unique    Ramform seismic vessels and our    HD3Dsm    seismic solution; and  •     positioning ourselves to participate in restructuring or    acquisition opportunities on an advantageous basis.     In the past, we have invested heavily in our multi-clientseismic data library and in high technology acquisitionequipment, including: •     our Ramform seismic vessels;  •     our high capacity computing facilities, together with the    development of specialized proprietary software for seismic    imaging, multi-component processing, signal enhancement and    visualization technology; and  • state-of-the-art    technology in our onshore seismic data acquisition equipment to    enable efficient acquisition of high quality seismic data in    varied terrain.
20

Table of Contents
     We believe that our main competitive strengths within ourgeophysical services businesses include: •     our highly experienced work force;  •     high operational reliability, safety and customer satisfaction;  •     our ability to tow more streamers and our superior streamer    retrievability, control and stability, which yield better cost    effectiveness on surveys and in adverse weather conditions,    respectively;  •     our high technology Ramform seismic vessels; and  •     the high channel counts and standardized equipment for our    onshore operations.***Geographic Areas of Operation***     We have divided our Marine Geophysical business into threeprimary areas of operations: •     North and South America;  •     Europe, Africa and the Middle East; and  •     Asia Pacific.     We have divided our Onshore geophysical business into threeprimary areas of operations: •     North America (U.S. and Canada);  •     Latin America (Mexico and South America); and  •     Eastern Hemisphere.     We acquire seismic data in most of the active oil and naturalgas exploration or production areas around the world, including: •     offshore and onshore Canada;  •     the Gulf of Mexico;  •     onshore in the U.S. mid continent, Rocky Mountains and    Alaskan North Slope regions;  •     offshore and onshore Mexico and other parts of Latin America;  •     offshore Brazil;  •     the North Sea;  •     the Mediterranean and Black Seas;  •     offshore West Africa, including shallow water areas;  •     the Middle East and North Africa;  •     the Caspian Sea area;  •     offshore China and Korea;  •     offshore India and onshore Bangladesh;  •     offshore in the Sakhalin area of Russia; and  •     offshore Australia, Indonesia and other countries in the Asia    Pacific region.***Contract and Multi-Client Operations***     *Contract Operations.* When we acquire seismic data on acontract basis, our customers direct the scope and extent of thesurvey and retain ownership of the data obtained. Contracts forseismic data acquisition, which are generally awarded on acompetitive bid basis, may include both a day-rate and aproduction rate
21

Table of Contents
element. Under these contracts, the customer assumes primaryresponsibility for interruption of acquisition operations due tofactors that are beyond our control, including weather andpermitting. Contracts are also awarded on a turnkey basis. Withturnkey contracts, the customers pay based upon the number ofseismic lines or square kilometers of seismic data collected andwe often bear some or all of the risk of interruption ofoperations due to factors that may be beyond our control.     During 2005, we used 91 percent of our active streamer 3Dvessel acquisition capacity, measured by time, to acquireseismic data on contract basis. We performed contract operationsduring 2005 in the North Sea; onshore in theU.S. mid-continent; onshore Canada; onshore Mexico; onshoreSouth America; offshore Brazil; offshore West Africa, includingshallow water; offshore North Africa; onshore Bangladesh; andoffshore Australia, Thailand and other countries in the AsiaPacific region.     *Multi-Client Operations.* From the perspective of an oiland natural gas company, licensing multi-client seismic data ona non-exclusive basis is typically less expensive on a per unitbasis than acquiring the seismic data on an exclusive basis.From our perspective, multi-client seismic data can be more costeffective to acquire and may be sold a number of times todifferent customers over a period of years. As a result,multi-client seismic data has the potential to be moreprofitable than contract data. However, when we acquiremulti-client seismic data we assume the risk that future salesmay not cover the cost of acquiring and processing such seismicdata. Obtaining pre-funding for a portion of these costs reducesthis risk, and increasingly we require a relatively high levelof pre-funding before beginning a project. We determine thelevel of pre-funding that we will require before initiating amulti-client seismic survey by evaluating various factorsaffecting the sales potential of each survey. These factorsinclude: •     the existence, quality and age of any seismic data that may    already exist in the area;  •     the amount of leased acreage in the area;  •     whether or when an award of a license to explore and develop an    area for production to be covered by a survey is expected to be    granted;  •     the prospectivity of the area in question for hydrocarbons and    for future licenses of multi-client data;  •     the existing infrastructure in the region to transport oil and    natural gas to market;  •     the historical turnover of the leased acreage;  •     the political and economic stability of the countries where the    data are to be acquired; and  •     the level of interest from oil and natural gas companies in the    area.     We own a significant library of marine multi-client data in mostof the major oil and natural gas basins of the world, includingthe Gulf of Mexico, the North Sea, offshore West Africa,offshore Brazil and the Asia Pacific region. Our onshore libraryis entirely in North America. During both 2004 and 2003, wereduced substantially the amount we invested in new multi-clientdata, as compared to earlier years, and devoted a higher portionof our capacity to the contract market. In 2005 our multi-clientinvestments increased by 35% compared to 2004.     In our multi-client operations, we make initial sales of thedata prior to project completion, which we refer to aspre-funding sales, and we refer to all further sales as latesales. We make a substantial portion of these late sales inconnection with acreage license round activity in those regionswhere we have a data library. Typically, customers are requiredto pay an amount for access to the data and additional amounts,or uplift fees, upon award of a concession or sometimes uponexecution of a production sharing or similar contract. Thetiming and regularity of such license round activity variesconsiderably depending upon a number of factors, including inparticular the geopolitical stability of the region in question.As a result, both the total amount and the timing of late salescan be difficult to forecast accurately, with potentiallysignificant revenue swings from quarter to quarter and from yearto year.     We attempt to protect our multi-client seismic data from misuseby customers primarily through contractual provisions thatpermit the use of the data only by that particular customer on anontransferable
22

Table of Contents
basis. Such provisions can be effective only if misuse of thedata by customers or third parties can be detected and if ourrights can be enforced through legal action.     Our multi-client data is marketed primarily through our ownsales organization.***Data Processing***     We provide seismic data processing services for our own seismicdata acquisition operations and for third parties. Generally, wecompete for data processing contracts on a competitive bidbasis. These contracts generally provide for the customer to paya flat fee per square kilometer processed for a prescribed setof processing procedures. Additional procedures may be quotedseparately and are often added during the course of a project.     We operate our data processing division as a part of ourregional Marine Geophysical business unit. Technical support,research and development and computer operations operate on aglobal basis. As of December 31, 2005, we operated fifteenland-based seismic data processing centers, with the largestcenters being located in Houston, Texas, U.S.; London, Englandand Perth, Australia. The largest seismic processing centersutilize computer resources organized in a global computerresource organization (Mega-Center). The three centers inHouston, London and Perth are inter-connected through highcapacity network links. In addition, most of our marine seismiccrews have the capability to perform data processing onboard thevessel.     Through our seismic data processing operations we provide: •     2D and 3D data processing of onshore and marine seismic surveys;  •     onboard (vessel) seismic data processing for reduced    delivery times and enhanced real-time quality control for data    that we acquire;  •     multi-component and 4D seismic data processing for reservoir    characterization and monitoring;  •     special process design to exploit the dense sampling of our    HD3Dsm    data acquisition;  •     specialized depth imaging of subsurface structures; and  •     other specialized signal enhancement techniques.***Our Marine Geophysical Segment***     *Marine Acquisition.* We believe that we operate one of themost advanced marine seismic data acquisition fleets in theworld. As of December 31, 2005, we had a total of ten 3Dmarine seismic streamer crews operating seismic vessels, and wehad one seafloor seismic crew.     *Streamer Seismic Acquisition.* Our conventional streameroperations represent the largest part of our marine seismic dataacquisition business. In our streamer operations, we use ourseismic vessel fleet to acquire 3D, 4D andHD3Dsmseismic data as described above under “Our GeophysicalServices — Overview.” For information relating toour fleet of vessels used to acquire marine seismic data, see“Vessel Fleet and Crews” below.     *Seafloor Seismic Acquisition.* We use seafloor seismicacquisition in areas where conventional streamer acquisitionoperations are not possible or economically feasible due toaccess limitations from shallow water or obstructions. Seafloorseismic acquisition is also used in areas where conventionalstreamer acquisition would not meet the desired geophysicalobjectives. In 2005 we had one seafloor seismic crew thatutilized a recording vessel, a source vessel and a cable-layingvessel. In September 2005 we announced that we would convert theseafloor seismic crew operations to streamer operations. One ofthe three vessels was converted to a six streamer 3D vessel, onewas converted to a 2D vessel, and the third vessel was returnedto its owners. The conversion was completed in February 2006.     *Vessel Fleet and Crews.* We acquire marine seismic datausing seismic crews primarily through owned and charteredvessels that have been constructed or modified to ourspecifications and outfitted with a complement of dataacquisition, recording, navigation and communications equipment.Our crews direct the
23

Table of Contents
positioning of a vessel using sophisticated navigationequipment, deploy and retrieve streamers, cables, receivers andenergy sources, and operate all of the seismic systems. Ourseismic crews do not operate the vessels. The vessel maritimecrews are employees of either the owner of the chartered vesselsor a contract operator for our vessels.     Most of our seismic vessels have an equipment complementconsisting of the following: •     recording instrumentation;  •     digital recording streamers;  •     acoustic positioning systems for source and streamer locations;  •     multiple navigation systems for vessel positioning; and  •     except for vessels that record only, a source control system    that controls the synchronization of the energy sources and an    air gun array firing system that activates the acoustic energy    source.     We provide in the following table information as ofDecember 31, 2005 about our marine seismic data acquisitionvessels.                                   **Maximum**            **Streamers**            **Deployed**      **Total** **Total** **Maximum** **(through** **Owned or**  **Year Rigged/** **Length** **Beam** **Streamer** **December 31,** **Charter****Vessel Name** **Converted** **(Feet)** **(Feet)** **Capability** **2005)** **Expiration**             **3D Seismic Vessels:**                        *Ramform Explorer*  1995   270   130   12   12   Owned *Ramform Challenger*  1996   284   130   16   12   Owned(1) *Ramform Valiant*  1998   284   130   20   12   2023(1) *Ramform Viking*  1998   284   130   20   12   2023(1) *Ramform Victory*  1999   284   130   20   16   2024(1) *Ramform Vanguard*  1999   284   130   20   12   2024(1) *Atlantic Explorer*  1994   300   58   6   6   Owned *American Explorer*  1994   300   72   8   8   Owned *Nordic Explorer*  1993   266   54   6   6   Owned *Orient Explorer*  1995/96   246   49   4   4   2006(2) **Seafloor Seismic Vessels:**                        *Falcon Explorer*  1997   266   53   N/A   N/A   Owned(4) *Bergen Surveyor*  1997   217   48   N/A   N/A   2006(3) *Ocean Explorer*  1993/95   269   59   N/A   N/A   Owned(4) **Support Vessels:**                        *Remus*  1998   136   32   N/A   N/A   Owned *Romulus*  1997   118   34   N/A   N/A   Owned  (1)     We have UK lease arrangements for each of the *Ramform    Valiant*, the *Ramform Viking*, the *Ramform    Victory*, the *Ramform Vanguard*and the *Ramform    Challenger.* Under the leases, we lease the vessels under    long-term charters that give us the option to purchase the    vessels for a *de minimis* amount at the end of the charter    periods. The leases are legally defeased because we have made    payments to banks in consideration for which the banks have    assumed liability to the lessors equal to basic rentals and    termination sum obligations. Please read notes 2 and 20 of    the notes to our consolidated financial statements included in    Item 18 of this annual report. (2)     The charter agreement for *Orient Explorer*has a one-year    term and will be extended annually for another year until 2011,    unless we terminate the charter by giving three months’    notice.
24

Table of Contents
(3)     We have terminated the charter for *Bergen Surveyor*and    the vessel was returned to its owners in the first quarter of    2006. (4) *Falcon Explorer*was converted to a 2D vessel and *Ocean    Explorer*was converted to a six streamer 3D vessel in the    first quarter of 2006.     In March 2006, we announced that we intend to build a new thirdgeneration Ramform seismic vessel at Aker Yards, Langsten,Norway. We currently expect delivery in the first quarter of2008. We expect the new vessel to cost approximately$85 million, excluding the cost of seismic equipment, andwe expect the total cost to be approximately $160 million,excluding project management cost and interest. We intend toseek an option to build a sister vessel at the same yard. AkerYards has constructed all six of our Ramform vessels, and thisis our first new build since 1999. The third generation Ramformwill be designed with the objective of further extending ourlead in 3D seismic acquisition productivity and efficiency, andwill be a key step in the implementation of ourHD3Dsmtechnical strategy.     *Competition in Our Marine Geophysical Segment.* Theseismic data acquisition and processing businesses are verycompetitive worldwide for both the contract market and themulti-client market. We compete for available seismic surveysbased on a number of factors, including technology, price,performance, dependability, vessel availability, turnaround timeand processing capacity availability. Our largest competitors ona global basis are WesternGeco, a joint venture between theseismic units of Schlumberger Limited and Baker HughesIncorporated, Compagnie Generale de Geophysique, S.A. andVeritas DGC Inc.     All of our major competitors in the seismic business bothacquire and process 3D seismic data. Our processing operationscompete primarily with WesternGeco, Compagnie Generale deGeophysique and Veritas DGC for time processing contracts. Fordepth imaging and other advanced processing applications, wealso compete with several smaller processing companies. Wecompete for time processing contracts based primarily on priceand technology, but processing capacity, turnaround time andprocessing center location are also important factors.***Our Onshore Segment***     Our Onshore segment consists of seismic acquisition operationson land and in very shallow water and transition zones. Thissegment also includes our onshore multi-client library. Weconduct contract onshore seismic acquisition throughout theworld. Our onshore multi-client library is entirely in theUnited States. During 2005, we conducted seismic acquisitionoperations in the United States (Gulf Coast, mid-continent,Rocky Mountains and Alaska), Canada, Mexico, Venezuela, Nigeriaand Bangladesh. During 2005, active crew counts have ranged fromfive to nine. As of December 31, 2005, we had seven crewsconducting activities in the United States, Canada, Venezuela,Nigeria and Bangladesh. As of that date, we were also in theprocess of starting up operations in Alaska, Mexico and Libya.We are pursuing additional contract opportunities in selectedmarkets worldwide and are expanding our multi-client onshorelibrary in the U.S. mid-continent.     In the market for onshore seismic services, we are one of thelarger worldwide operators, measured in terms of revenues. Wecompete in the onshore segment based on price, crew availabilityand other factors. We believe that we can remain competitive bycapitalizing on our project execution and management skills andby continuing to provide a high quality technical product. Themajority of our recording equipment pool is relatively uniform,facilitating changing crew counts and channel counts on anyspecific crew as the market dictates.**Our Production Segment**     On March 27, 2006, our Board of Directors authorizedproceeding with a demerger plan under Norwegian law to separateour geophysical and production businesses and calling anextraordinary general meeting of our shareholders to vote on thetransaction, to be held on April 28, 2006. If thetransaction is approved by our shareholders and completed, ourshares would be split into shares of two independently listedcompanies. For more information relating to our possibleseparation, see “Proposed Separation of the Geophysical andProduction Businesses” above.
25

Table of Contents
***Overview***     We are one of the largest operators of FPSO vessels in the NorthSea, measured by production capacity and number of vessels.Through our Production segment, we own and operate four FPSOvessels with a combined production capacity of339,000 barrels of oil per day and a crude oil storagecapacity of one million barrels. All four of our FPSOs, the*Ramform Banff, Petrojarl I, Petrojarl Foinaven*and*Petrojarl Varg*, are double hulled, rated for harshenvironments and capable of working in deepwater fields.     We believe that our fleet of FPSO vessels is one of the mosttechnologically advanced in the industry. We have experienceoperating in some of the industry’s most demandingenvironments in the North Sea and the continental shelf of theAtlantic Ocean.     An FPSO system is a ship-based type of mobile production unitthat produces, processes, stores and offloads oil and processes,re-injects or exports gas from offshore fields with widelydiffering production characteristics, sizes and water depths.The selection of a particular mobile production unit from amongthe several types of readily movable offshore production systemsdepends on several factors, including overall reservoir andenvironmental characteristics of the field to be developed,availability of transportation infrastructure and financial andschedule constraints. FPSO systems typically perform the samefunction as fixed offshore platforms in the offshore productionof oil and natural gas, with the exceptions of drilling andheavy well maintenance. However, FPSO systems generally providea number of advantages over fixed platforms, including: •     being capable of storing and offloading oil;  •     being suitable for a wide range of field sizes and water depths;  •     being reusable on more than one developed reservoir;  •     generally costing less and being easier to install and remove    than fixed platforms; and  •     reducing the time from the discovery of oil and natural gas to    production.***Our FPSO Strategy***     Our strategy for production services includes: •     maximizing the value of our present contracts through careful    cost management,  •     maximizing future redeployment opportunities, and  •     seeking growth opportunities through a proposed joint venture    with Teekay Shipping Corporation to establish a broader    geographical position.     We believe opportunities exist in the North Sea, particularly onthe Norwegian Continental Shelf where we currently operate twovessels, to redeploy our FPSO vessels when our existing FPSOcontracts terminate. We also intend to continue to evaluateredeployment opportunities in other regions.***Proposed Joint Venture with Teekay***     In February 2006, we announced a proposed joint venture withTeekay Shipping Corporation to develop new FPSO projects. Weexpect to finalize the arrangements for this joint ventureduring the second quarter of 2006.     We believe the agreement with Teekay will be an important partof the international expansion strategy for our productionbusiness. The joint venture allows us more effectively to pursuefurther growth in the market for mobile production solutionsworldwide. Teekay has a global marketing organization andcustomer and shipyard relationships, which complements ourengineering expertise and experience as a quality operator ofFPSOs in the harsh North Sea environment.     Teekay has a fleet of more than 140 tanker vessels, offices in15 countries and 5,100 seagoing and shore-based employees.
26

Table of Contents
***The FPSO Market***     The market for production services differs fundamentally fromthe geophysical market. Offshore production generally takesplace a relatively long time after exploration drilling has beencompleted. As a result, oil and natural gas companies typicallymake production-related decisions based on different financialparameters than those used for decisions relating to seismic ordrilling activities. As offshore hydrocarbon basins around theworld in general have matured, oil and natural gas companies ina number of oil producing areas have increasingly focused on thedevelopment of smaller fields with relatively smaller oruncertain reservoir estimates or shorter expected producinglives. For development of these smaller fields to be profitable,the oil and natural gas companies must reduce development costlevels and financial exposure. As a result, producers havefocused increasingly on subsea installations and reusable FPSOsystems instead of the more traditional fixed steel and concreteplatforms, which generally are not reusable.***Our FPSO Systems***     We provide in the following table information as ofDecember 31, 2005 about our four FPSO vessels. In additionto these four vessels, as of December 31, 2005 we used twoshuttle tankers and one storage tanker from third-partycontractors under operating leases expiring at various datesthrough 2014. In addition, as of December 31, 2005 we owneda 40% interest in a French company that owns the FPSO*Ikdam*, which is producing the Isis field located offshoreTunisia on a fixed day rate contract. As of that date,production from this vessel was approximately 1,500 barrelsper day with a maximum processing capacity of30,000 barrels per day.                                 **Production**        **Approximate** **Approximate** **Capacity**   **Storage**  **Year** **Total Length** **Total Width** **(Barrels of** **Displacement** **Capacity****FPSO Vessel Name** **Delivered** **(Feet)** **(Feet)** **Oil per Day)** **(Metric Tons)** **(Barrels)**             *Ramform Banff*(1)  1998   395   175   95,000   32,100   120,000 *Petrojarl I*  1986   683   105   47,000   51,000   180,000 *Petrojarl Foinaven*(1)  1996   827   116   140,000   72,000   280,000 *Petrojarl Varg*  1999   702   125   57,000   100,000   420,000  (1)     We have UK lease arrangements for the *Petrojarl Foinaven*and for the *Ramform Banff*topside production    equipment. Under the leases, we lease the vessel and equipment    under long-term charters that give us the option to purchase the    vessel and equipment for a *de minimis*amount at the end    of the charter periods. The leases are legally defeased because    we have made payments to banks in consideration for which the    banks have assumed liability to the lessors equal to basic    rentals and termination sum obligations. Please read    notes 2 and 20 of the notes to our consolidated financial    statements included in Item 18 of this annual report.***Ramform Banff***     The *Ramform Banff*operates on the Banff field, located inthe UK sector of the North Sea about 120 miles east ofAberdeen, Scotland. Our contract for this work dates to 1997,and oil production from the field commenced in January 1999. In2005, the wells from the nearby Kyle field were connected to the*Ramform Banff.*     Under the existing contract with the field operator, we willcontinue to produce the Banff field with the *Ramform Banff*until the end of the life of the field, which is estimatedto be 2014. The new contract contains a two-tierproduction-dependent tariff that varies at different productionlevels. We receive $5 per barrel of oil produced per day upto 15,400 barrels and $3 per barrel of oil producedper day in excess of 15,400 barrels. We also receive afixed day rate of £40,000 (approximately $69,000) per day,with a minimum total rate of $126,800 per day. These ratesare applicable for production through 2014, with provisions forcost index adjustments. If field production extends beyond 2014,we will be entitled to an increased day rate. Under the amendedcontract, the field operator has the right to terminate thecontract at its sole discretion on six months’ notice. Upontermination of the contract, the field operator has the optionto acquire the sub-sea facilities of
27

Table of Contents
the *Ramform Banff*free of charge or cost. In the eventthat the field operator does not exercise its option, we areobligated to remove the sub-sea facilities at our cost and, uponcompletion of our obligations under the contract, the operatorwill owe us five million British pounds, escalated by1.5% per annum from 2000.***Petrojarl I***     We operate the *Petrojarl I*under contract to Statoil toproduce the Glitne field in the Norwegian sector of the NorthSea. We began production of the field with the *Petrojarl I*in August 2001. Based on production estimates filed by theoperator, we expect that production under the contract maycontinue beyond 2008.     The contract provides for compensation consisting of atariff-based element of $3.50 per barrel and a fixed dayrate of $12,750 plus up to $5,000 per day for waterinjection, subject to a minimum of $58,500 and a maximum of$108,500. In addition, we are entitled to receive an additionalamount of NOK 475,585 (approximately $70,262) per day foroperating expenses. Statoil may cancel the contract on sixmonths’ notice. In addition, Statoil may terminate thecontract upon specified force majeure events; the insolvency orbankruptcy of our subsidiary K/ S Petrojarl I A/ S ordemonstration by that subsidiary that it is not capable ofperforming the work; or our substantial breach of the contract.We may cancel the contract on three months’ notice if theminimum variable rate has been received for 90 days in a120 day period, subject, however, to Statoil’s rightto continue the contract by increasing the tariff element.***Petrojarl Foinaven***     The *Petrojarl Foinaven*is under contract to a consortiumof field co-operators led by Britoil PLC, a subsidiary of BPplc, for production of the Foinaven field west of the Shetlands.The Foinaven contract is not limited as to time. Britoil mayterminate the contract with a minimum of two years’ notice.We currently expect that the vessel will remain on the field fora substantial period. Britoil may terminate the contract uponthe total loss of the vessel, a breach of the contract that isnot remedied within agreed deadlines, specified insolvency andbankruptcy related events or specified force majeure events. Inaddition, we may terminate the contract with prior notice ifproduction-dependent tariff revenue falls below specified levels.     The contract provides for compensation consisting of a fixed dayrate of $71,258 and a two-tier production-dependent tariff thatvaries at different production levels. We receive $3.50 perbarrel of oil produced per day up to 25,000 barrels and$2.95 per barrel of oil produced per day in excess of25,000 barrels, and we receive $0.75 per barrel of oilproduced per day from East Foinaven.     We have additional obligations that may arise under the contractrelating to the Foinaven project, including obligations to: •     compensate Britoil up to a maximum of $10 million for    breaches of contract; and  •     pay for pollution damage caused by diesel or lubricants.***Petrojarl Varg***     The *Petrojarl Varg*produces the Varg field on theNorwegian Continental Shelf of the North Sea under a contractwith the license owners of PL038. Under the existing charter andoperating agreement with the PL 038 license owners, ourcompensation consists of a fixed base day rate of $90,000 and atariff of $6.30 per barrel produced per day. The charterand operating agreement may be terminated with 90 dayswritten notice, but we are not entitled to terminate theagreements as long as the mean weekly production during normaloperation on the license exceeds approximately15,700 barrels of oil per day. According to the currentproduction profile of the Varg field, *Petrojarl Varg*could be available for redeployment on a new field in 2008.***Competition in Our Production Operations***     Our production operations generally compete with oil companiesdeciding to operate FPSOs themselves, with other FPSO operators,with fixed installations and tension leg platforms, with sub-seaproduction installations tied back to existing infrastructure,with semi-submersible andjack-up platforms andwith other
28

Table of Contents
floating or land-based production systems. Competition betweenFPSO systems and other offshore production systems is based on anumber of factors including water depth, the availability orproximity of transportation infrastructure, the size of theproducing field and time considerations, estimated reserves, thecost and schedule for modifications, as well as local regulatoryframework. Competition tends to be limited within segments ofprocessing plant sophistication, operating conditions andregulatory regimes, as FPSO systems having differentspecifications cannot be redeployed easily or cost effectivelybetween these segments. Our fleet of FPSOs is designedspecifically for harsh weather operations, limited shuttlingdistances and demanding regulatory regimes, such as typicallyfound in the North Sea and the Atlantic Continental Shelf. Thelimited shuttling distances required for our FPSOs results inrelatively low need for storage capacity. In addition to theFPSO operations and other offshore production systems of themajor oil and natural gas companies, our FPSO competitorsinclude numerous companies that own a small number of FPSOvessels.     FPSOs perform similar tasks as fixed installations, with theexception of drilling and heavy well maintenance. To combinedrilling and heavy well maintenance with production, some oilcompanies have opted for semi-submersible platforms. The choiceof development system between an FPSO and either a fixedinstallation or another floating system is dependent on anoverall technical and financial evaluation of the individualfield to be developed.**Oil and Natural Gas Production Segment (Pertra)**     We sold Pertra to Talisman on March 1, 2005 as described inmore detail under “Operating and Financial Review andProspects — Sale of Our Oil and Natural Gas SubsidiaryPertra” in Item 5 of this annual report. Theoperations of Pertra were included in our results of operationsthrough February 2005. Following our sale of Pertra, we do nothave any continuing direct economic interest in the activitiesof Pertra except for certain additional contingent salesproceeds as described under “Operating and Financial Reviewand Prospects — Sale of Our Oil and Natural GasSubsidiary Pertra” in Item 5 of this annual report andour continued production of the Varg field using *PetrojarlVarg*as described in more detail above under“— Our Production Segment —*Petrojarl Varg.”***Other Factors Related to Our Business*****Our Research and Product Development***     We desire to be an industry leader in those oilfield servicemarkets in which our advanced technologies and services may beused. We are committed to providing our customers withinnovative services that help to lower the costs of finding andproducing oil and natural gas. As a result, we incur researchand development costs in an attempt to keep our key assets andservices at the forefront of engineering and technical advances.For information regarding our research and developmentexpenditures, please see our consolidated statements ofoperations in Item 18 of this annual report.     Some of the highlights from our research and developmentactivities in 2005 include: •     development of fiber optic sensor technology for use in    reservoir monitoring;  •     development of software to construct 3D velocity models;  •     development of software to improve the quality of acquired data;    and  •     improvements to our Cube Manager data processing package.***Intellectual Property***     Our patents, trademarks, service marks, copyrights and licensesprotect our proprietary technology, including our Ramformseismic vessels andHD3DSMseismic solution software. Our intellectual property rightscollectively represent a material asset to our business.However, no single patent, trademark, copyright, license orpiece of technical information is of material importance to ourbusiness when taken as a whole. As of December 31, 2005, weheld 160 patents under the laws of the United States, the UnitedKingdom and Norway. The duration of these patents varies from 3to 18 years, depending upon the date filed and the
29

Table of Contents
duration of protection granted by each country. For moreinformation relating to the risks associated with our dependenceupon proprietary technology, see “KeyInformation — Risk Factors — Risk FactorsRelating to Our Business Operations Generally — Ourresults of operations depend in part upon our ability to protectour proprietary technology” in Item 3 of this annualreport.***Seasonality***     We incorporate by reference in response to this item theinformation in “Operating and Financial Review andProspects — Seasonality” in Item 5 of thisannual report.***Operating Conditions and Insurance***     Our operations often are conducted under extreme weather andother hazardous conditions. These operations are subject torisks of injury to personnel and loss of equipment. We havesafety compliance programs staffed by full-time professionalemployees and a program for developing, implementing andmanaging our responsibility for the health and safety of ouremployees and the environments in which we operate. Systems forreporting and tracking the occupational health of our employeesare in place in our business units. Company-wide initiativesfocus on the further development of our environmental managementsystems. All our FPSO units and associated shuttle tankers areISO 14001 certified (environmental certification). We considereach employee to be a vital contributor to health, safety andenvironment in our company, and we are fully committed to ourhealth, safety and environment program.     Since 1994 we have operated our own captive re-insurance companythat provides insurance for our seismic equipment, includingmarine acquisition vessels and equipment, onshore equipment,data processing and information technology hardware andsoftware, and some of our production equipment including FPSOsand shuttle tankers. As part of this insurance, all of ourseismic vessels, shuttle tankers and FPSOs have a level ofcoverage against war and terrorism risks that is customary forour industry. We do not generally maintain such insurance forour land-based assets because we do not believe such insuranceis cost effective. As noted below, this insurance is subject todeductibles and limits of coverage and is supplemented bycommercial reinsurance arrangements with creditworthyre-insurers.     We obtain a substantial portion of our casualty insurancethrough this wholly owned captive re-insurance company. As ofDecember 31, 2005, we retain risk through this captivecompany of $4.5 million for each accident, with a maximumrisk retention of $7.2 million per year, in excess ofunderlying deductibles. Our various operating companies have adeductible per occurrence when obtaining this casualty insurancefrom the captive company, ranging from $125,000 peraccident for our seismic vessels, up to $200,000 peraccident for our streamers and $750,000 per accident forour FPSOs.***Governmental Regulation***     In various areas of the world, we are required to obtain and wehave licenses to acquire multi-client seismic data. Licensingand permitting requirements vary widely. We believe that we havecomplied in all material respects with the licensing andpermitting requirements relating to our acquisition ofmulti-client data.     Our operations are also affected by the exploration andproduction licensing requirements of various governmentalauthorities. The timing and extent of licensing of areas forexploration and production activities influence the level ofseismic activity within a particular country. Prospectivelicensees often purchase multi-client seismic data prior to theaward of licenses. Following a license award, license holderswill generally acquire seismic data for the newly licensed areasif they have not previously obtained multi-client data. In theNorth Sea, the governments of Norway and the United Kingdomgenerally hold licensing rounds for exploration and productionevery year. In the Gulf of Mexico, licensing of blocks forexploration and production are held twice each year, onceoffshore Texas and once offshore Louisiana. In Brazil, a licenseround has occurred each year during the last few years. In otherareas of the world the timing and extent of these licensingrounds might be more irregular, and the licenses awarded may besubject to resolution of
30

Table of Contents
border disputes. The length of the actual license to explore foroil and natural gas varies from region to region and is subjectto governmental regulation.     Additionally, our operations are affected by a variety of otherlaws and regulations, including laws and regulations relating to: •     permitting or licensing agreements for oil and natural gas    exploration, development and production activities;  •     exports and imports;  •     currency;  •     taxes;  •     occupational health and safety; and  •     the protection of the environment.     Our operations are subject to a variety of laws and regulationsgoverning the discharge of materials into the environment orotherwise relating to environmental protection. Numerousgovernmental departments issue rules and regulations toimplement and enforce such laws that are often complex andcostly to comply with and that can carry substantial penaltiesor fines for failure to comply. Under these laws andregulations, we may be liable for remediation or removal costs,damages and other costs associated with releases of hazardousmaterials including oil into the environment.     We believe that we are currently in compliance in all materialrespects with the requirements of environmental, export/importand occupational health and safety laws and regulations. Pleaseread “Key Information — Risk Factors —Risk Factors Relating to Our Business OperationsGenerally — Unpredictable changes in governmentalregulations could increase our operating costs and reduce demandfor our services” in Item 3 of this annual report.***Capital Expenditures***     We incorporate by reference in response to this item theinformation in “Operating and Financial Review andProspects — Liquidity and CapitalResources — Capital Requirements and Commitments”in Item 5 and note 27 of the notes to our consolidatedfinancial statements in Item 18 of this annual report,which, among other things, provide information on the nature andgeographic distribution of our capital expenditures.***Geographic Mix of Operations and Segment    Information***     We incorporate by reference in response to this item theinformation regarding the geographic mix of our operations andsegments, including revenue breakdowns, in note 27 of thenotes to our consolidated financial statements in Item 18of this annual report.**Organizational Structure**     We provide in the following table a list of our subsidiaries andaffiliated companies as of March 23, 2006.       **Name** **Jurisdiction** **Ownership**         PGS Shipping AS     Norway  100%    Oslo Seismic Services Ltd.      Isle of Man  100%    PGS Geophysical AS     Norway  100%    PGS Production AS     Norway  100%    Multiklient Invest AS     Norway  100%    Petroleum Geo-Services, Inc.      United States  100%    Petroleum Geo-Services (UK) Ltd.      United Kingdom  100%    Seahouse Insurance Ltd.      Bermuda  100%
31

Table of Contents
       **Name** **Jurisdiction** **Ownership**         PGS Mexicana SA de CV     Mexico  100%    Dalmorneftegeofizika PGS AS     Norway  49%    Geo Explorer AS     Norway  50%    Baro Mekaniske Verksted AS     Norway  10%    Calibre Seismic Company     United States  50%    PGS Capital, Inc.      United States  100%    Diamond Geophysical Services Company     United States  100%    PGS Exploration (Nigeria) Ltd.      Nigeria  100%    PGS Data Processing Middle East SAE     Egypt  100%    PGS Data Processing, Inc.      United States  100%    Petroleum Geo-Services Asia Pacific Pte. Ltd     Singapore  100%    PGS Australia Pty. Ltd.      Australia  100%    Atlantis (UK) Ltd.      United Kingdom  100%    PGS Egypt for Petroleum Services     Egypt  100%    Hara Skip AS     Norway  100%    PGS Exploration, SDN BHD     Malaysia  100%    PGS Exploration, Inc.      United States  100%    PGS Exploration Pty. Ltd.      Australia  100%    PGS Ocean Bottom Seismic, Inc.      United States  100%    PGS Exploration (UK) Ltd.      United Kingdom  100%    PGS Floating Production (UK) Ltd.      United Kingdom  100%    PGS Pension Trustee Ltd.      United Kingdom  100%    PGS Reservoir (UK) Ltd.      United Kingdom  100%    Atlantic Explorer Ltd.      Isle of Man  50%    Oslo Seismic Services Inc.      United States  100%    Oslo Explorer Plc     Isle of Man  100%    Oslo Challenger Plc     Isle of Man  100%    PGS Shipping (Isle of Man) Ltd.      Isle of Man  100%    PGS Onshore, Inc.      United States  100%    PGS Onshore (Canada), Inc.      Canada  100%    PGS Americas, Inc.      United States  100%    Seismic Energy Holding, Inc.      United States  100%    PGS Caspian AS     Norway  100%    PGS Multi-Client Seismic Ltd.      Jersey  100%    PGS Marine Services (Isle of Man) Ltd.      Isle of Man  100%    Golar-Nor Offshore AS     Norway  100%    Golar-Nor Offshore (UK) Ltd.      United Kingdom  100%    K/ S Petrojarl I AS     Norway  98.5%    Golar-Nor (UK) Ltd.      United Kingdom  100%    Deep Gulf LLC     United States  50.1%    PGS Nopec (UK) Ltd.      United Kingdom  100%    PGS Nominees Ltd.      United Kingdom  100%    Petrojarl IV DA     Norway  99.25%    SOH, Inc.      United States  100%
32

Table of Contents
       **Name** **Jurisdiction** **Ownership**         PT PGS Nusantara     Indonesia  100%    PGS Processing (Angola) Ltd.      United Kingdom  100%    Seismic Exploration (Canada) Ltd.      United Kingdom  100%    PGS Ikdam Ltd.      United Kingdom  100%    Sakhalin Petroleum Plc     Cyprus  100%    Ikdam Production, SA     France  40%    PGS Investigacào Petrolifera Limitada     Brazil  99%    Sea Lion Exploration Ltd.      Bahamas  100%    PGS Administración y Servicios S.A. de C.V.      Mexico  100%    PGS Servicios C.A     Venezuela  100%    PGS Venezuela de C.A     Venezuela  100%    PGS Overseas AS     Norway  100%    PGS Suporte Logistico e Servicos Ltda.      Brazil  100%    PGS Finance, Inc.      United States  100%    Valiant International Petroleum Ltd.      United Kingdom  24.6%    PGS Japan K.K     Japan  100%    PGS Petrojarl Varg AS     Norway  100%    PGS Tanker AS     Norway  100%    PGS Ramform Banff Ltd.      United Kingdom  100%    PGS Ramform Banff AS     Norway  100%**Leased Premises**     Our principal offices are at Lysaker, Norway in leased premises.We also maintain leased premises in other cities in Norway, theUnited States, Angola, Azerbaijan, Australia, Bangladesh,Bolivia, Brazil, Canada, China, Ecuador, Egypt, England, France,Indonesia, Kazakhstan, Libya, Malaysia, Mexico, Nigeria, Russia,Scotland, Singapore, the United Arab Emirates and Venezuela. Webelieve that all leased properties are well maintained and aresuitable for our present activities.**ITEM 4A.     *****Unresolved Staff Comments***     None.**ITEM 5.*****Operating and Financial Review and Prospects***     *You should read the discussion under this caption incombination with consolidated financial statements and therelated notes in Item 18 of this annual report and“Key Information — Selected Financial Data”in Item 3 of this annual report. This discussion is basedupon, and the consolidated financial statements included inItem 18 of this annual report have been prepared inaccordance with, United States generally accepted accountingprinciples. The following information contains forward-lookingstatements. You should refer to the section in this annualreport captioned “Forward-Looking Statements” forcautionary statements relating to forward-looking statements.***Overview**     We are a technologically focused oilfield service companyprincipally involved in providing geophysical services worldwideand providing floating production services in the North Sea.Globally, we provide a broad range of geophysical and reservoirservices, including seismic data acquisition, processing andinterpretation and field evaluation. In the North Sea, we ownand operate four harsh environment floating production, storageand offloading vessels (“FPSOs”).
33

Table of Contents
     In 2005, we managed our business in three segments as follows: • *Marine Geophysical*, which consists of streamer seismic    data acquisition, marine multi-client library and data    processing;  • *Onshore*, which consists of all seismic operations on land    and in shallow water and transition zones, including our onshore    multi-client library; and  • *Production*, which owns and operates four harsh    environment FPSOs in the North Sea.     We discuss below our results of operations based on the threeremaining business segments and Pertra as a separate businesssegment through February 2005. We manage our Marine Geophysicalsegment from Lysaker, Norway, our Onshore segment from Houston,Texas, and our Production segment from Trondheim, Norway.     On March 1, 2005, we sold Pertra AS, a small oil andnatural gas company that we managed as a separate segment, toTalisman Energy (UK) Ltd. (“Talisman”) asdescribed in more detail below. Pertra was included in ourreported numbers through February 2005. Pertra owned 70% of andwas operator for Production License 038 (“PL038”) onthe Norwegian Continental Shelf (“NCS”) and also ownedparticipating interests in six additional NCS licenses withoutproduction. Pertra has been renamed Talisman Production Norge AS.     On March 27, 2006, our Board of Directors authorizedproceeding with a demerger plan under Norwegian law to separateour geophysical and production businesses and calling anextraordinary general meeting of our shareholders to vote on thetransaction, to be held on April 28, 2006. If thetransaction is approved by our shareholders and completed, ourshares would be split into shares of two independently listedcompanies. For more information relating to our possibleseparation, see “— Proposed Separation of theGeophysical and Production Businesses” in Item 4 ofthis annual report. The effects on the consolidated financialstatement of the proposed demerger are described separately. Fora more comprehensive discussion of our history and development,including our business segments and our strategic focus, pleaseread “Information on the Company” in Item 4 ofthis annual report.**Effects of the Demerger on Consolidated FinancialStatements**     The Production business will be presented as held for sale(discontinued operations) in the consolidated financialstatements from the date of board approval of the demerger plan.In addition, historical financial information of the Pertraoperations will be presented as discontinued from the same date,as the continued business relations with Pertra (now TalismanProduction Norge AS) related to *Petrojarl Varg*will bediscontinued with the demerger of the Production business.**2005 Refinancing**     In 2005, we (a) repaid $250 million of our unsecured8% Senior Notes due 2006 and (b) refinanced$741 million of the $746 million of unsecured10% Senior Notes due 2010 and our $110 million securedcredit facility. The 8% Senior Notes and the10% Senior Notes were issued in our 2003 financialrestructuring. We redeemed $175 million of the8% Senior Notes at 102% of par value in April 2005 and theremaining $75 million of such notes at 101% of par value inNovember 2005.     In December 2005, we completed a tender offer and consentsolicitation for our $746 million 10% Senior Notes due2010. As a result, we retired approximately $741.3 millionaggregate principal amount of the notes at a price of 113.64% ofpar value. Debt redemption and refinancing costs totaled$107.3 million (including a $0.4 million write-off ofdeferred debt issue costs) and $9.9 million in capitalizeddeferred debt issue costs.     As part of the refinancing, we established a $1 billionsenior secured credit facility consisting of a seven-year$850 million term loan and a five-year $150 millionrevolving credit facility. The new revolving credit facilityreplaced our previous $110 million secured credit facility.For additional information about our new credit facility, pleaseread “— Liquidity and CapitalResources — Sources of Liquidity — CapitalResources” below.
34

Table of Contents
**Sale of Our Oil and Natural Gas Subsidiary Pertra**     On March 1, 2005, we sold our wholly owned subsidiaryPertra AS to Talisman for an initial sales price ofapproximately $155 million, which resulted in a gain of$149.8 million, including the $2.5 million received togrant an option to make certain amendments to the charter andoperating agreement for the *Petrojarl Varg*as describedbelow.     As a part of the agreement with Talisman, we are entitled to anadditional sales consideration equal to the value, on a postpetroleum tax basis, of 50% of the relevant revenues from theVarg field in excess of $240 million for each of the yearsended December 31, 2005 and 2006. In January 2006 wereceived $8.1 million, representing the 2005 portion of thecontingent consideration, and recognized that amount as anadditional gain from the 2005 sale. This amount was recognizedas an additional gain from the sale in 2005.     We also granted an option enabling Talisman to change thetermination clause with respect to PL038. The option expired onFebruary 1, 2006 without being exercised. *Petrojarl Varg*will therefore continue to produce the Varg field for afixed base day rate of $90,000 and a variable rate of$6.30 per barrel produced. We are entitled in some cases toterminate the agreement if the production of the Varg fieldfalls below 15,700 barrels per day. Based on the currentproduction profile of the Varg field, *Petrojarl Varg*could become available for redeployment on a new field in 2008.**2003 Financial Restructuring**     In 2003, we implemented a financial restructuring through areorganization under Chapter 11 of the U.S. BankruptcyCode. The reorganization became effective and was substantiallyconsummated on November 5, 2003. Under the reorganizationplan, $2,140 million of our senior unsecured debt wascancelled, and the associated creditors received the following: •     $746 million of unsecured 10% Senior Notes due 2010;  •     $250 million of unsecured 8% Senior Notes due 2006;  •     $4.8 million of an eight-year unsecured senior term loan    facility (which the Company fully repaid in May 2004);  •     91% of our new ordinary shares as constituted immediately post    restructuring, with an immediate reduction of this shareholding    to 61% in a rights offering of 30% of the new ordinary shares to    the pre-restructuring shareholders for $85 million, or    $14.17 per share; and  •     $40.6 million of cash, of which $17.9 million was    distributed in December 2003 and the remainder in May 2004.     Under the reorganization plan, •     our pre-restructuring share capital was cancelled and 20,000,000    new ordinary shares, par value NOK 30 per share, were    issued;  •     the pre-restructuring shareholders received 4%, or 800,000, of    the new ordinary shares and the right to acquire 30%, or    6,000,000, of the new ordinary shares for $85 million    ($14.17 per share) in the rights offering;  •     pre-restructuring owners of $144 million of trust preferred    securities received 5%, or 1,000,000, of the new ordinary    shares; and  •     the principal amount of our interest-bearing debt and capital    lease obligations was reduced by approximately    $1,283 million to approximately $1,210 million    immediately after the restructuring.**2003 Fresh Start Reporting and Changes in AccountingPolicies**     In connection with our emergence from Chapter 11reorganization, we adopted “fresh start” reporting forfinancial statement purposes, effective November 1, 2003,in accordance withSOP 90-7. UnderSOP 90-7, we
35

Table of Contents
adjusted the recorded value of our assets and liabilities toreflect their fair market value as of the date we emerged fromChapter 11 reorganization.     In connection with our adoption of fresh start accounting, wereviewed our accounting policies with a view toward creating newpolicies that are less complex, more transparent and betterreflect current operations. The most significant changes in ouraccounting policies were: •     expenditures incurred in connection with steaming and    mobilization are expensed as incurred. Onsite project costs such    as positioning, deploying and retrieving equipment at the    beginning and end of a project are considered mobilization or    demobilization costs and are expensed as incurred, unless the    project relates to the building of the multi-client data    library, in which case such costs are included in the costs of    the multi-client survey. Such expenses were previously    recognized as part of contract costs or multi-client project    costs as appropriate, and as such would not have been fully    expensed immediately,  •     the successful efforts method of accounting for oil and natural    gas assets was adopted,  •     we made certain changes to our amortization policy for our    multi-client library, including an increase in minimum    amortization by reducing the maximum amortization period from    eight to five years after completion of a survey,  •     depreciable lives of Ramform seismic acquisition vessels and    FPSOs, other than the *Petrojarl I*, were reduced from    30 to 25 years.     Please refer to note 2 of our consolidated financialstatements included in Item 18 of this annual report fordisclosure of our significant accounting policies, includingthose policies that changed under fresh-start. Please refer tonote 3 for disclosure of the fresh-start adjustments.**Critical Accounting Policies and Estimates**     We discuss below our operating results and financial conditionbased on our consolidated financial statements, which areprepared in accordance with U.S. GAAP. In order to preparethese financial statements, we must make estimates andassumptions that affect the reported amount of assets andliabilities, our disclosure of contingent assets and liabilitiesand the amounts of reported revenues and expenses. We evaluateour estimates and assumptions from time to time and may employoutside experts to assist in our evaluations. We believe thatour estimates and assumptions are reasonable, but we acknowledgethat actual results may vary from what we have estimated orassumed. Our significant accounting policies are described innote 2 to the consolidated financial statements included inItem 18 of this annual report.     We list and summarize in greater detail below those accountingpolicies that we believe to be the most critical in thepreparation and evaluation of our financial statements and thatinvolve the use of assumptions and estimates that require ahigher degree of judgment and complexity. As a result, ourreported assets, liabilities, revenues and expenses could bematerially affected if the assumptions and estimates we makewere changed significantly, and our actual financial position,results of operations, cash flows and future developments maydiffer materially from the assumptions and estimates we havemade. Our critical accounting policies and related estimates forthe periods discussed below relate to: •     revenue recognition;  •     multi-client data library, including cost capitalization, sales,    amortization and impairment;  •     long-lived assets, particularly impairment and depreciation,    depletion and amortization;  •     deferred tax assets;  •     fresh start reporting; and  •     oil and natural gas accounting, including capitalization,    amortization and impairment.
36

Table of Contents
***Revenue Recognition***     We recognize revenue on our contract sales of data and on ourother geophysical services as we perform the services and areable to charge the customer for these services. Because of thenature of the geophysical services business, we incur andrecognize costs from time to time prior to the time revenues canbe recognized. As a result, a non-symmetrical matching ofrevenues and expenses may result in variability of results ofoperations between accounting periods. We generally recognizerevenue from our floating production services in two components.First, we recognize tariff based revenues, based on the numberof barrels produced, as production occurs. Second, we recognizeday rate revenues over the passage of time. We recognizerevenues from the production and sale of oil and natural gaswhen the production is delivered and ownership has passed to thecustomer. After the sale of Pertra in March 2005, revenues fromthe production and sale of oil and natural gas are not material.     Sales of data from our multi-client library generally fall intoone of three categories. •     Late sales — we grant a license to the customer for a    specified portion of the library.  •     Volume sales agreements — we grant a license or    licenses to a specified number of blocks in a defined    geographical area so that the customer can select and access the    specific blocks over a period of time.  •     Pre-funding arrangements — we obtain funding from a    limited number of customers before a seismic acquisition project    commences. In return for the pre-funding, the customer typically    gains the ability to direct or influence the project    specifications, to access data as it is being acquired and to    pay discounted prices.     We recognize revenue: •     from late sales when the customer executes a valid license    agreement and has been granted access to the library and    collection is reasonably assured;  •     from volume sales agreements ratably based on the total revenue    and volume of data specified in the agreement as the customer    executes licenses for specific blocks and has been granted    access to the data; and  •     from pre-funding arrangements as the data is acquired, generally    based on physical progress, on a proportional performance basis.***Multi-Client Data Library***     We discuss revenue recognition relating to our multi-clientlibrary above under “— Revenue Recognition.”     We capitalize as an asset the costs associated with acquiringand processing multi-client data. We base our amortization ofthe multi-client data library on the sales forecast method.Under this method, we amortize the cost of a particular surveycontained in the library based on the ratio between the cost ofthe survey and the total forecasted sales of data for suchsurvey. In applying this method following our adoption of freshstart reporting, we categorize surveys into three amortizationcategories with amortization rates of 90%, 75% or 60% of salesamounts. Each category will include surveys where the remainingunamortized cost as a percentage of remaining forecasted salesis less than or equal to the amortization rate applicable toeach category. We have also established maximum book valuecriteria for the library projects based on a five-year life formarine and onshore projects and a three-year life for allderivative processed projects. The maximum book value for eachproject at year-end is the total cost of the project lessaccumulated straight-line minimum amortization. Prior to ouradoption of fresh start reporting, we amortized our multi-clientdata library based on the ratio of actual sales to expectedsales with a minimum amortization based on five to eight yearlives.     We periodically evaluate the projects in the multi-clientlibrary for impairment. Effective January 1, 2004, weclassify as amortization expense in our consolidated statementsof operations write-downs of individual multi-client surveysthat are based on changes in project specific expectations andthat are not individually material. We expect this additional,non-sales related, amortization expense to occur regularly
37

Table of Contents
because we evaluate projects individually. We classify asimpairment in our consolidated statements of operationswrite-downs related to significant changes in estimatesaffecting a larger part of our multi-client library where theeffects are material. Prior to 2004 we classified as impairmentexpense all write-downs of multi-client library.     In determining the ordinary amortization rates applied to, andfair value of, our multi-client data library, we considerexpected future multi-client sales, sales costs, marketdevelopments and past experience. Our sales expectations includeconsideration of geographic locations, prospects, politicalrisk, exploration license periods and general economicconditions. These sales expectations are highly subjective,cover extended periods of time and are dependent on a number offactors that we do not control. Accordingly, these expectationscould differ significantly from year to year. Our ability torecover costs included in the multi-client data library throughsales of the data depends upon continued demand for the data andthe absence of technological or regulatory changes or otherdevelopments that would render the data obsolete or reduce itsvalue.     Through 2003, the sales expectations for our multi-clientlibrary declined significantly, reflecting a weakening of themarket for multi-client data. As a result, our multi-clientlibrary amortization rates increased over time and we recognizedan impairment of the multi-client data library of$90 million for the Predecessor for the ten months endedOctober 31, 2003. In 2004 and 2005, we had higher totalsales than we expected. Although the total sales expectationsfor many of the surveys have increased, expectations for certainindividual surveys have decreased or been delayed, resulting inadditional non-sales related amortization on those surveys.Because we apply our impairment tests and calculate our minimumamortization on a survey-by-survey basis, and due to theinherent uncertainty of sales forecasts, we are likely to haveadditional non-sales related amortization in the future.     Due to our adoption of fresh-start reporting, the book value ofthe portion of our multi-client library that was recognized inthe fresh-start balance sheet will be reduced if and when werealize pre-fresh-start tax assets. Future amortization costswill be reduced accordingly. For additional information, pleasesee “— Deferred Tax Assets” below andNote 21 of the notes to our consolidated financialstatements included in Item 18 of this annual report.***Oil and Natural Gas Accounting***     Following our adoption of fresh-start reporting, we used thesuccessful efforts method of accounting for oil and natural gasproperties. Under this method, all costs of acquiring unprovedoil and natural gas properties and drilling and equippingexploration wells are capitalized pending determination ofwhether the properties have proved reserves. If an explorationwell is determined not to have commercial quantities ofreserves, the drilling and equipment costs for the well areexpensed and classified as exploration costs at that time. Alldevelopment drilling and equipment costs are capitalized.Capitalized costs of proved properties are amortized on aproperty-by-property basis using theunit-of-productionmethod whereby the ratio of annual production to beginning ofperiod proved oil and natural gas reserves is applied to theremaining net book value of such properties. Geological andgeophysical costs are expensed as incurred and presented asexploration costs.     The estimates of proved oil and natural gas reserves as ofDecember 31, 2004 and 2003 were prepared by our engineersin accordance with guidelines established by the SEC and theFinancial Accounting Standards Board, which require that reserveestimates be prepared under existing economic and operatingconditions with no provision for price and cost escalationsexcept by contractual arrangements. The estimates were reviewedby an independent reservoir engineering consultant. Oil andnatural gas reserve quantity estimates are subject to numerousuncertainties inherent in the estimation of quantities of provedreserves and in the projection of future rates of production andthe timing of development expenditures. The accuracy of suchestimates is a function of the quality of available data and ofengineering and geological interpretation and judgment. Both in2003 and 2004, we had substantial increases of reserves causedby new extensions and discoveries. In addition, we had a fairlysubstantial increase in 2003 caused by a revision of previousestimates. For additional information about these estimates,please read note 30 of the consolidated financialstatements included in Item 18 of this annual report.
38

Table of Contents
     Prior to our adoption of fresh start reporting, we used the fullcost method of accounting for oil and natural gas properties.Under this method, all costs associated with the acquisition,exploration and development of oil and natural gas propertiesare capitalized. Costs are accumulated on a country-by-countrybasis. Under this method, capitalized costs are amortized usingthe unit-of-productionmethod on a country-by-country basis. Unevaluated properties areexcluded from the amortization base. Future development costsand dismantlement and abandonment costs are included in theamortizable cost base. In accordance with SEC guidelines, thecost bases of proved oil and natural gas properties accountedfor under the full cost method are limited, on acountry-by-country basis, to the estimated future net cash flowsfrom proved oil and natural gas reserves using prices and othereconomic conditions in effect at the end of the reportingperiod, discounted at 10%, net of related taxes. If thecapitalized cost of proved oil and natural gas propertiesexceeds this limit, the excess is charged to expense asadditional depletion, depreciation and amortization.     We sold our oil and natural gas subsidiary Pertra to Talisman inMarch 2005 as described in “— Sale of our Oil andNatural Gas Subsidiary Pertra” above. For additionalinformation about our oil and natural gas accounting, pleaseread note 2 of the consolidated financial statementsincluded in Item 18 of this annual report.***Accounting for Long-Lived Assets***     We review long-lived assets or groups of assets for impairmentwhenever events or changes in circumstances indicate that thecarrying amount may not be recoverable. If the total of theundiscounted future cash flows is less than the carrying amountof the asset or group of assets, an impairment loss isrecognized for the difference between the estimated fair valueand the carrying value of the asset or group of assets. Weassess for possible impairment long-lived assets, such asmulti-client data library, property and equipment, and provedoil and natural gas assets accounted for under the successfulefforts method, upon the occurrence of a triggering event.Events that can trigger assessments for possible impairmentsinclude, but are not limited to (a) significant decreasesin the market value of an asset, (b) significant changes inthe extent or manner of use of an asset, (c) a physicalchange in the asset, (d) a reduction of proved oil andnatural gas reserves based on field performance and (e) asignificant decrease in the price of oil or natural gas. Weassess for impairment unproved oil and gas properties inaccordance with the guidelines of SFAS No. 19. Priorto the adoption of fresh-start reporting, we assessed forimpairment oil and natural gas assets in accordance with thefull cost accounting guidelines as described under “Oil andNatural Gas Accounting” above.     Estimating undiscounted future cash flows requires us to makejudgments about long-term forecasts of future revenues and costsrelated to the assets subject to review. These forecasts areuncertain as they require assumptions about demand for ourproducts and services, future market conditions and futuretechnological developments. Significant and unanticipatedchanges in these assumptions could require a provision forimpairment in a future period. Given the nature of theseevaluations and their application to specific assets andspecific times, it is not possible to reasonably quantify theimpact of changes in these assumptions.     Through 2003, the future cash flow expectations for most of ourassets declined in line with difficult markets. As a result, weexperienced substantial impairments both in 2002 and in 2003. Inaddition, we recognized a substantial reduction in asset valueswhen we adopted fresh start accounting in November 2003. In linewith a strengthening of the markets, the future cash flowexpectations have generally increased subsequent to 2003,although expectations for certain individual assets havedecreased. However, we have not identified any impairment needsfor individual assets in 2004 and 2005, except for theimpairments recorded as a consequence of the decision todiscontinue our four component seafloor operations in 2005 of$4.6 million.***Deferred Tax Assets***     At December 31, 2005, we had a total of $623 millionof deferred tax assets (net of deferred tax liabilities) indifferent jurisdictions, predominantly in Norway and the UK. Atadoption of fresh-start reporting on November 1, 2003 andat December 31, 2004, we established valuation allowancesfor all of our deferred tax assets, with the exception of taxassets relating to Pertra. A valuation allowance, by taxjurisdiction, is established when it is more likely than notthat all or some portion of the deferred tax assets will
39

Table of Contents
not be realized. The valuation allowance is periodicallyadjusted based upon the available evidence. During 2005, weconcluded that certain valuation allowances were no longernecessary as available evidence, including recent profits andestimates of projected near term future taxable income,supported a more likely than not conclusion that the relateddeferred tax assets would be realized. As a result, in 2005 wereleased a portion of our valuation allowance, resulting in therecognition of a deferred tax asset of $20 million on theconsolidated balance sheets at December 31, 2005.     The estimates of projected near term future taxable income arebased on a variety of factors and assumptions, many of which aresubjective and are outside of our control. Accordingly, theseestimates could differ significantly from year to year, and wemight end up realizing more or less of the deferred tax assetsthan we have recognized on the balance sheet.     If and when we realize the benefits of deferred tax assets, forwhich we established a valuation allowance at the adoption offresh-start reporting, the positive effect does not flow throughthe consolidated statement of operations as a tax benefit, butis rather (as required underSOP 90-7) recordedas a reduction of the carrying value of long-term intangibleassets existing at adoption of fresh-start reporting, until thevalue of such assets is reduced to zero. If there are benefitsof deferred tax assets to be realized after those intangibleassets have been reduced to zero, the benefits would be creditedto shareholders’ equity. As a result of realization of suchdeferred tax assets in 2005, we reduced the carrying values ofthe multi-client library by $25.3 million and otherintangible assets by $1.8 million. Of the total valuationallowance as of December 31, 2005, $390.0 millionrelates to pre-reorganization amounts and will only affect netincome through reduction of amortization expense for intangibleassets. For additional information about how we account fordeferred tax assets, please see Note 2 and Note 21 of thenotes to our consolidated financial statements included inItem 18 of this annual report.***Fresh-Start Reporting***     We adopted fresh-start reporting upon our emergence fromChapter 11 in accordance withSOP 90-7.Accordingly, all assets and liabilities were adjusted to reflecttheir reorganization value as of November 1, 2003, whichapproximates fair value at the date of reorganization. Weengaged independent financial advisors to assist in thedetermination of the reorganization value of the combined entityand for most of the individual assets and liabilities. Assetsand liabilities were valued based on a combination of the cost,income and market approach. We also considered technical,functional and economic obsolescence. Please see“— 2003 Fresh-Start Reporting and Changes inAccounting Policy” above.     Similar to the estimates made for long-lived assets as describedabove, the estimates of fair value made for purposes of freshstart reporting required judgments regarding long-term forecastsof future revenues and costs related to all significant assetsand liabilities. These forecasts are uncertain in that theyrequire assumptions about demand for our products and services,future market conditions and technological developments.Significant and unanticipated changes to these assumptions couldrequire a provision for impairment in a future period.     We have indemnified the lessors in the UK leases for, amongother things, the tax consequences resulting from changes in taxlaws or interpretations thereof or adverse rulings by the taxauthorities (“Tax Indemnities”). In connection withthe adoption of fresh-start reporting in November 2003, werecorded a liability of 16.7 million British pounds(approximately $28.3 million) relating to the TaxIndemnities. We release applicable portions of this liability ifand when the UK Inland Revenue accepts the lessors’ claimsfor capital allowances under each lease. In 2005, we released9.4 million British pounds (approximately$17.2 million) of the liability. The remaining accruedliability as of December 31, 2005 is 7.3 millionBritish pounds (approximately $12.7 million) and relates tothe *Petrojarl Foinaven*lease, where an issue relating tothe length of asset life remains. For additional informationabout our UK leases, please read “— Liquidity andCapital Resources — UK Leases” below.**Seasonality**     Our Marine Geophysical segment experiences seasonality as aresult of weather-related factors. Weather conditions in theNorth Sea generally prevent the full operation of seismic crewsand vessels in the winter
40

Table of Contents
season and, due to vessel relocation, generally adversely impactour first and fourth quarter results and, to a lesser extent,our second quarter results. Storm seasons in the tropics canalso affect our operations when we have crews in the Gulf ofMexico or tropical Asia. During these periods, we generallyrelocate our seismic vessels to areas with more favorableweather conditions to conduct seismic activities, or we conductrepairs and maintenance. On the other hand, our fourth quarterrevenue has historically been positively affected byend-of-year sales ofmulti-client data to oil and natural gas companies. In addition,timing of licensing activities and oil and natural gas leasesales may significantly affect quarterly operating results.     Our Onshore segment can also be affected by weather and seasons,depending on where we deploy our crews at a particular time. OurProduction segment generally does not experience materialseasonal effects, other than normal maintenance andrefurbishment activities for our FPSO vessels in our Productionsegment that typically take place during the summer months.     Our results of operations fluctuate from quarter to quarter dueto a number of other factors. Oil and natural gas industrycapital expenditure budgets and spending patterns influence ourresults. These budgets are not necessarily spent in equal orprogressive increments during the year, with spending patternsaffected by individual customer requirements and industry-wideconditions. In addition, under our revenue recognition policy,revenue recognition from data licensing contracts depends, amongother things, upon when the customer selects the data. Inaddition, many of our contract projects are relatively shortterm. The timing ofstart-up and completionand crew or vessel movement can significantly affect our resultsof operations from period to period. As a result, our seismicservices revenue does not necessarily flow evenly orprogressively during a year or from year to year.**Impact of Foreign Currency Fluctuations**     We conduct business in various currencies and are subject toforeign currency exchange rate risk on cash flows related tosales, expenses, financing and investing transactions incurrencies other than the U.S. dollar. For a more completediscussion of the impact of foreign currency fluctuations andthe extent to which we hedge this exposure, please see“Quantitative and Qualitative Disclosures About MarketRisk — Foreign Currency Exchange Rate Risk” inItem 11 of this annual report.**Results of Operations*****Overview***     Our results of operations for the years 2005, 2004 and 2003(Successor and Predecessor) are presented below in an expandedformat that shows the primary components of and key driversaffecting our results of operations. Our consolidated statementsof operations show separately the ten month period endedOctober 31, 2003 (Predecessor) and the two month periodended December 31, 2003 (Successor) as we emerged fromChapter 11 bankruptcy proceedings on November 5, 2003and adopted fresh-start reporting effective as ofNovember 1, 2003. As indicated in the discussion of ourresults for 2003 below, Successor and Predecessor are in someareas combined for purposes of the discussion. Successorfinancial statements are prepared on the basis of fresh startreporting from November 1, 2003 and include changes in thecarrying value of assets and liabilities and changes to certainaccounting policies.     In addition, the results of operations discussed below excludethe results from our Atlantis oil and natural gas subsidiary andour Tigress software subsidiary, both of which were sold in 2003and are presented as discontinued operations in our consolidatedfinancial statements included in Item 18 of this annualreport. The results of operations discussed below include theresults for Pertra, our oil and natural gas subsidiary that wesold in March 2005, through February 2005. The *Petrojarl Varg*(Production segment) has provided production services to theoperators of PL 038, in which Pertra owned a 70% interest.Accordingly, for the period during which we owned Pertra, 70% ofthe associated revenues from the *Petrojarl Varg*have beeneliminated as inter-segment revenues. Effective from the sale ofPertra, we report this portion of the revenues from the*Petrojarl Varg*as external revenues. As a result, therevenues of Production included in our consolidated statement ofoperations have increased.
41

Table of Contents
     We discuss below our results of operations based on the threeremaining business segments — Marine Geophysical,Onshore and Production — and Pertra as a separatebusiness segment through February 2005. We operate our MarineGeophysical and Onshore businesses globally and generaterevenues primarily through contract acquisition sales andmulti-client sales (pre-funding and late sales). Our Productionsegment generates revenues from contract production activitiesin the Norwegian and U.K. sectors of the North Sea. Pertragenerated oil production revenues from its 70% interest in PL038 in the Norwegian Sector of the North Sea.***Revenues***     The table below presents our mix of revenues for each of thethree years by business segment.                         **Predecessor**    **Successor Company** **Company** **Combined**           **Two Months** **Ten Months** **Twelve Months**  **Years Ended December 31,** **Ended** **Ended** **Ended**    **December 31,** **October 31,** **December 31,**  **2005** **2004** **2003** **2003** **2003**             **(In thousands of dollars)****Marine Geophysical**                        Contract $424,192  $297,749  $48,273  $302,451  $350,724     Multi-client pre-funding  40,006   30,535   6,510   43,187   49,697     Multi-client late sales  218,781   203,397   36,786   123,435   160,221     Other  41,703   39,124   7,813   31,040   38,853                    724,682   570,805   99,382   500,113   599,495                 **Onshore**                        Contract  122,415   110,288   18,442   106,324   124,766     Multi-client pre-funding  16,148   12,761   1,807   14,636   16,443     Multi-client late sales  13,976   10,112   1,210   8,005   9,215                    152,539   133,161   21,459   128,965   150,424                 **Production**                    *Petrojarl I*  53,394   61,303   11,086   58,529   69,615 *Petrojarl Foinaven*  89,191   96,595   18,726   93,373   112,099 *Ramform Banff*  46,483   51,509   6,572   38,616   45,188 *Petrojarl Varg*  89,920   87,133   8,604   59,191   67,795     Other  1,689   1,662   241   349   590                    280,677   298,202   45,229   250,058   295,287 **Other/elimination**  1,686   (56,834)  (3,243)  (29,369)  (32,612)                **Total revenues (services)**  1,159,584   945,334   162,827   849,767   1,012,594 **Revenues (products) — Pertra**  36,742   184,134   9,544   112,097   121,641                 **Total revenues** $1,196,326  $1,129,468  $172,371  $961,864  $1,134,235                      Our revenues for 2005 increased by $66.8 million ascompared with 2004. Marine Geophysical increased by$153.9 million, while Onshore revenues increased by$19.3 million. These increases were offset by a reductionof revenues from Pertra, which was sold in March 2005, of$147.4 million, offset by a decrease in elimination ofinter-segment revenues of $58.5 million, mainly caused by70% of the revenues from *Petrojarl Varg*being reported asexternal from March 2005 as a result of the sale of Pertra.Total Production revenues decreased $17.5 million. Revenuesfor 2004 decreased $4.7 million as compared with combined2003 revenues for Predecessor and Successor. Pertra revenuesincreased by $62.5 million, but this increase was more than
42

Table of Contents
offset by a decrease of revenues in Marine Geophysical($28.7 million) and Onshore ($17.2 million) and higherelimination of inter-segment revenues as described below.     *Marine Geophysical — 2005 vs. 2004.* MarineGeophysical 2005 revenues increased by $153.9 million (27%)as compared with 2004. Revenues from contract seismicacquisition increased by $126.5 million (42%), primarily asa result of improved pricing, better contractual terms andgeneral improvement of operational efficiency in 2005. In 2004,in addition to weaker pricing, revenues were negatively affectedby significant operating disturbances during completion of alarge turnkey project offshore India in the second quarter.Revenues from multi-client late sales increased by$15.4 million (8%). In 2005, we increased our investment inmulti-client data, and revenues from multi-client pre-fundingincreased by $9.5 million (31%). Pre-funding as apercentage of cash investments in multi-client data decreased to87% in 2005 compared to 99% in 2004. We had a fairly consistentallocation of total 3D streamer capacity (measured by activestreamer months) with approximately 91% contract and 9%multi-client in 2005, compared to 88% and 12%, respectively, in2004.     *Marine Geophysical — 2004 vs. 2003.* MarineGeophysical 2004 revenues decreased by $28.7 million (5%)as compared with 2003 (combined). Revenues from contract seismicacquisition decreased by $53.0 million (15%), primarily dueto a close down of our ocean bottom 2C crew in late 2003.Revenues from this crew amounted to $40.5 million in 2003(combined). In addition, contract revenues were negativelyimpacted by a weak contract market in the first half of 2004 andsignificant operating disturbances during completion of a largeturnkey project offshore India in the second quarter. Revenuesfrom multi-client late sales increased by $43.2 million(27%), reflecting overall high demand in the second half of2004. In 2004, we reduced further our acquisition ofmulti-client data, and revenues from multi-client pre-fundingdecreased by $19.2 million (39%). Pre-funding as apercentage of cash investments in multi-client data increased to99% in 2004 compared to 72% in 2003. In 2004, we allocated thetotal 3D streamer capacity for our seismic fleet betweencontract and multi-client data acquisition (measured by activestreamer months) approximately 88% and 12%, respectively, ascompared to approximately 78% and 22%, respectively, in 2003.     *Onshore — 2005 vs. 2004.* Onshore revenues for2005 increased by $19.3 million (14%) as compared with2004. Onshore had higher revenues in the U.S. and Canada bothwithin the contract market and within the multi-client market(where all revenues are generated in the U.S.). Furthermore, thenew project in Nigeria caused increasing revenues in the EasternHemisphere, offset by a further reduction of the activity leveland revenues in Mexico.     *Onshore — 2004 vs. 2003.* Onshore revenues for2004 decreased by $17.3 million (11%) as compared with 2003(combined). Onshore had significant activity in Alaska, Mexicoand Saudi Arabia in 2003, but in 2004 Onshore had no activity inSaudi Arabia or Alaska. In addition, activity in Mexico declinedat the end of 2004 as we completed one of our two large projectsin that region in the third quarter.     *Production — 2005 vs. 2004.* Production revenuesfor 2005 decreased $17.5 million (6%) as compared to 2004.*Petrojarl I*revenues declined $7.9 million (13%) and*Petrojarl Foinaven*revenues declined $7.4 million(8%) primarily due to natural field production declines. Inaddition, production from *Petrojarl Foinaven*was reducedby problems related to oil/water separation and relatedmaintenance slowdown and shutdown. Revenues from *RamformBanff*decreased by $5.0 million (10%), primarily due toa $3.7 million lump sum modification job for CanadianNatural Resources included in 2004 revenues, while productioncompensation has been realized at the minimum day rate both in2004 and 2005. Production levels on *Ramform Banff*havebeen fairly consistent, just above 10,000 barrels per day,both in 2004 and 2005. Revenues from *Petrojarl Varg*increased by $2.8 million (3%), including inter-segmentrevenues from Pertra (approximately 70% of *Petrojarl Varg*revenues through February 2005). The increase is dueprimarily to increased production. Both 2004 and 2005 werenegatively affected by a damage to the main production riser onthe Varg field that reduced production from November 5,2004 until March 9, 2005. The compensation structure in the*Petrojarl Varg*production contract was amended, effectiveMay 29, 2004, to a combination of a fixed day rate and aproduction tariff (as compared to a pure production tariffpreviously).     *Production — 2004 vs. 2003.* Production revenuesfor 2004 increased $2.9 million (1%) as compared to 2003(combined). *Petrojarl Foinaven*revenues declined$15.5 million (14%) primarily due to a natural field
43

Table of Contents
production decline. *Petrojarl I*revenues declined$8.3 million (12%) primarily for the same reason. Further,the production on *Petrojarl I*was shut down fromSeptember 12 to October 29, 2004 due to a labor conflict onthe NCS, but the revenue impact was limited as we received forcemajeure compensation during the period. Revenues from *RamformBanff*increased by $6.3 million (14%), primarily due toa $3.7 million lump sum modification job for CanadianNatural Resources and a new production contract effectiveJanuary 1, 2004 with a minimum day-rate of $125,000.Revenues from *Petrojarl Varg*increased by$19.3 million (29%), including inter-segment revenues fromPertra (approximately 70% of *Petrojarl Varg*revenues).The increase is due primarily to increased production, despite ashut down for approximately two weeks in October 2004 related toa labor conflict on the NCS and damage to the main productionriser on the Varg field that reduced production to approximately50% of the field’s potential from November 5, 2004through the end of the year.     *Elimination of inter-segment revenues.* In 2005,elimination of inter-segment revenues (which reducesconsolidated revenues) decreased by $60.0 million ascompared to 2004 primarily due to reporting 70% of theProduction revenues relating to *Petrojarl Varg*asexternal from March 2005, as a result of the sale of Pertra.Through February 2005, 70% of *Petrojarl Varg* revenuesrelated to Pertra’s interest in the Varg field and wereeliminated in the consolidated financial statements. Theseinter-segment revenues, which aggregated $9.1 million,$60.4 million and $45.1 million in 2005, 2004 and 2003(combined), respectively, are eliminated in our consolidatedstatement of operations.     *Pertra.* Pertra revenues for 2005 decreased$147.4 million (80%) as compared with 2004, primarily as aconsequence of the sale of Pertra in March, as 2005 includesonly two months of revenues from Pertra compared to full yearfor 2004. Pertra revenues for 2004 increased $62.5 million(51%) as compared with 2003 (combined) primarily due toincreased production of oil.
44

Table of Contents
***Cost of Sales***     The following table shows our cost of sales (products andservices), excluding depreciation and amortization, by segmentand each segment’s cost of sales as a percentage ofrevenues generated by that segment:                          **Predecessor**    **Successor Company** **Company** **Combined**           **Two Months** **Ten Months** **Twelve Months**  **Years Ended December 31,** **Ended** **Ended** **Ended**    **December 31,** **October 31,** **December 31,**  **2005** **2004** **2003** **2003** **2003**             **(In thousands of dollars, except percentage data)****Marine Geophysical** $373,504  $342,460  $55,903  $248,965  $304,868      % of revenue  51.5%  60.0%  56.3%  49.8%  50.9%**Onshore** $124,334  $92,290  $13,043  $76,634  $89,677      % of revenue  81.5%  69.3%  60.8%  59.4%  59.6%**Production** $184,313  $167,764  $21,208  $133,114  $154,322      % of revenue  65.7%  56.3%  46.9%  53.2%  52.3%**Other** $8,613  $9,558  $900  $6,776  $7,676     Transfer of cost(1)  (12,418)  (24,160)  3,990   (11,093)  (7,103)                **Total cost of sales (services)** $678,346  $587,912  $95,044  $454,396  $549,440      % of revenue  58.5%  62.2%  58.4%  53.5%  54.3%                **Cost of sales (products)**                        Pertra $28,542  $93,035  $7,040  $61,910  $68,950     Elimination(1)  (6,238)  (48,197)  (5,130)  (28,528)  (33,658)                **Total cost of sales (products)** $22,304  $44,838  $1,910  $33,382  $35,292      % of revenue  60.7%  24.3%  20.0%  29.8%  29.0%                **Total cost of sales** $700,650  $632,750  $96,954  $487,778  $584,732      % of revenue  58.6%  56.0%  56.2%  50.7%  51.6%                 (1)     Elimination of inter-segment charter hire related to    *Petrojarl Varg*and inter-segment transfers of costs.     *Cost of sales (services) — 2005 vs. 2004.* Costof sales (services) increased by $90.4 million in 2005as compared with 2004 as costs increased in Marine Geophysical,Onshore and Production. The main reasons are increased activitylevels in Marine Geophysical and Onshore, general cost increases(in particular fuel prices and payroll) and increased repair andmaintenance costs both on the seismic vessels and the FPSOs.Marine Geophysical cost of sales (services) increased$31.0 million, mainly caused by charter of third party 2Dvessel capacity in 2005, price increases of fuel and lube andincreased repair and maintenance cost, partly offset by anincrease in capitalized multi-client cost. The cost of sales asa percentage of revenues for Marine Geophysical decreased to 52%in 2005 compared to 60% in 2004, in line with the substantialincrease of revenues. Onshore cost of sales increased$32.0 million, mainly caused by the increased activitylevel. The cost of sales as a percentage of revenues for Onshoreincreased to 82% in 2005 compared to 69% in 2004, mainly causedby significant mobilization andstart-up costs inNigeria and Libya where the corresponding expected projectrevenues, which are recognized based on progress of production,were not all recognized in 2005. Production’s cost of salesincreased by $16.5 million, primarily due to increasedrepair and maintenance expenses.     Production’s cost of sales includes all of the operatingcosts, excluding depreciation and amortization, for *PetrojarlVarg.* Through February 2005, 70% of these costs areeliminated from consolidated cost of sales (services) andincluded in cost of sales (products) and 70% of*Petrojarl Varg*revenues are eliminated from cost of sales(products) representing the 70% interest Pertra had in theVarg field.
45

Table of Contents
     *Cost of sales (products) — 2005 vs. 2004.* Costof sales (products) decreased by $22.5 million in 2005as compared with 2004 as 2005 only includes two months of costsfor Pertra, as a consequence of the sale of that subsidiary inMarch 2005, compared to twelve months of costs for 2004.     *Eliminations.* Total elimination of inter-segment costs(which reduces consolidated operating costs) in 2005 decreasedby $57.4 million compared to 2004 primarily due todiscontinuing the elimination of 70% of *Petrojarl Varg*charter hire from March 1, 2005*.*     *Cost of sales (services) — 2004 vs. 2003.* Costof sales (services) increased by $38.5 million in 2004as compared with 2003 (combined) primarily due to reducedmulti-client activity in our Marine Geophysical business as weincreased our focus in 2004 on contract marine seismicacquisition as compared to 2003. As a result, we reduced costscapitalized as investment in multi-client library by$49.5 million. In addition, cost of sales increased due togeneral cost increases driven by a weakening of theU.S. dollar against the British pound and the Norwegiankroner (which increases the reported U.S. dollar cost ofexpenses incurred in those currencies) and increased fuelprices, partially offset by the effect of closing down our oceanbottom 2C crew in late 2003. Production’s cost of salesincreased by $13.4 million, primarily due to increasedmaterials purchases reimbursed by a customer, a weakening of theU.S. dollar exchange rate (which increases the reportedU.S. dollar cost for Production since a significant part ofthese costs are incurred in British pounds and Norwegian kroner)and increased maintenance expense.     *Cost of sales (products) — 2004 vs. 2003.* Costof sales (products) increased by $9.5 million in 2004as compared with 2003 (combined) as a result of increasedPertra operating costs due primarily to a significant increasein production and increased well intervention costs.***Exploration Costs***     Exploration costs were $1.4 million in 2005 compared to$16.3 million in 2004. Exploration costs in 2004 include$11.4 million for the drilling of a dry exploration well inPL038. We incurred exploration costs in our oil and natural gassubsidiary Pertra, which was sold in March 2005. Such costsinclude costs to drill exploration wells and other costs relatedto exploration for oil and natural gas, including geological andgeophysical services, excluding depreciation and amortization.     Prior to adopting fresh start reporting, we accounted for oiland natural gas assets using the full cost method and allexploration costs were capitalized.***Depreciation, Depletion and Amortization***     Depreciation, depletion and amortization (“DD&A”)expenses result primarily from the allocation of capitalizedcosts over the estimated useful lives of our geophysical seismicvessels and equipment, our FPSO vessels, our seismic andoperations computer equipment, leasehold improvements, buildingsand other fixtures, and depletion of our oil and gas explorationand production assets (consisting of licenses, tangible andintangible costs of drilling wells and production equipment)that are depleted using a units of production method based onproved oil and gas reserves. DD&A expenses also include theamortization of our multi-client data library, which we refer toas MCDL Amortization, and the amortization of certain intangibleassets recognized upon our adoption of fresh start reportingeffective as of November 1, 2003.     The following table shows our total DD&A expenses bysegment. For our Marine Geophysical and Onshore segments, wehave provided separately (1) DD&A expenses excludingMCDL Amortization, or Adjusted DD&A, and (2) MCDLAmortization because we believe that separately disclosing MCDL
46

Table of Contents
Amortization provides users useful information about a keycomponent impacting the results of our geophysical operations.                         **Successor** **Successor** **Successor** **Predecessor**    **Company** **Company** **Company** **Company** **Combined**                 **Two Months** **Ten Months** **Twelve Months**  **Year Ended** **Year Ended** **Ended** **Ended** **Ended**  **December 31,** **December 31,** **December 31,** **October 31,** **December 31,**  **2005** **2004** **2003** **2003** **2003**             **(In thousands of dollars)****Marine Geophysical:**                         Adjusted DD&A $54,120  $55,277  $9,565  $59,730  $69,295      MCDL amortization  118,229   186,435   29,786   131,485   161,271                       DD&A  172,349   241,712   39,351   191,215   230,566                 **Onshore:**                         Adjusted DD&A  16,355   18,677   3,571   14,292   17,863      MCDL amortization  15,310   21,208   2,653   15,133   17,786                       DD&A  31,665   39,885   6,224   29,425   35,649                 **Production:**                         DD&A  44,064   44,561   8,112   43,418   51,530 **Pertra:**                         DD&A  6,710   38,965   743   30,826   31,569 **Corporate and other:**                         Adjusted DD&A  3,637   2,414   361   4,911   5,272      MCDL amortization  930   825   908   1,781   2,689                       DD&A  4,567   3,239   1,269   6,692   7,961                 **Total:**                         Adjusted DD&A  124,886   159,894   22,352   153,177   175,529      MCDL amortization  134,469   208,468   33,347   148,399   181,746                       DD&A $259,355  $368,362  $55,699  $301,576  $357,275                      *2005 vs. 2004.* Adjusted DD&A for 2005 decreased by$35.0 million (22%) compared to 2004 primarily due toreduced depreciation from Pertra of $32.3 million as Pertrais only included for two months of 2005 compared to a full yearfor 2004.     MCDL Amortization for 2005 decreased by $74.0 million (35%)as compared with 2004. Amortization for 2005 included$35.4 million of non-sales related amortizations (minimumamortization of $20.4 million and write-downs of$15.0 million), compared to $48.8 million in 2004.Please read note 2 of the consolidated financial statementsincluded in Item 18 of this annual report for a descriptionof our policy related to amortization of multi-client library.In total, MCDL Amortization as a percentage of multi-clientrevenues was 46% in 2005 compared to 81% in 2004. Excluding thenon-sales related amortization, the amortization was 34% and 62%of revenues in 2005 and 2004 respectively, reflecting generallylower amortization rates on sales in 2005 as well as asignificant increase in sales relating to surveys that werealready fully amortized ($150.6 million in 2005 compared to$65.8 million in 2004).     In 2005 the net book value of our multi-client library wasreduced by $25.3 million as a result of the recognition ofdeferred tax assets, which had been offset by full valuationallowance when we adopted fresh-start reporting onNovember 1, 2003 (please see “— CriticalAccounting Policies and Estimate — Deferred TaxAssets” above). As such, this reduction is not a policy orjudgment relating to the multi-client library, but anapplication of AICPA Statement of Opinion (“SOP”)90-7, “Financial Reporting by Entities in Reorganizationunder the Bankruptcy Code”, which requires realization ofpre-restructuring tax assets to be
47

Table of Contents
recorded as a reduction of intangible assets recognized uponadoption of fresh-start reporting (see separate section forincome tax expense below). Additional realization of suchvaluation allowance, and corresponding reduction of the net bookvalue of intangible assets, may occur in future periods.     *2004 vs. 2003.* Adjusted DD&A for 2004 decreased by$15.6 million (9%) compared with 2003(combined) primarily due to reduced depreciation in MarineGeophysical ($14.0 million) and Production($7.0 million). Reductions in those two segments werepartly offset by increased depreciation and depletion of oil andgas assets in Pertra, reflecting increased production.Depreciation in Marine Geophysical and Production generallydecreased due to the significant reduction in carrying values offixed assets as a result of our adoption of fresh-startreporting effective as of November 1, 2003, partly offsetby a reduction of the estimates of the useful depreciable livesfor several of the assets in our seismic and FPSO fleet.Additionally, depreciation capitalized as part of the cost ofmulti-client library was reduced by $9.1 million to$4.0 million in 2004.     MCDL Amortization for 2004 increased by $26.7 million (15%)as compared with 2003 (combined). The increase relates primarilyto charges for minimum amortization that amounted to$28.9 million and additional amortization of$19.9 million to write certain surveys down to fair valuecompared to minimum amortization of $36.6 million in 2003(impairments were presented separately). Please read note 2of the consolidated financial statements included inItem 18 of this annual report for a description of ourpolicy related to amortization of multi-client library. Intotal, MCDL Amortization as a percentage of multi-clientrevenues was 81% in 2004 compared to 76% in 2003.***Selling, General and Administrative Costs***     Selling, general and administrative costs in 2005 increased by$2.6 million as compared with 2004 to $67.4 million.The primary reason for the increase is increased bonus expensesto a broad category of employees due to achievement of keyperformance indicators under the bonus program established for2005, partly offset by a reduction due to Pertra only beingincluded for two months in 2005. Also, because we incur most ofour selling, general and administrative costs in Norwegiankroner and other currencies other than the U.S. dollar, theweakening of the U.S. dollar against these currenciesincreased our reported cost.     Selling, general and administrative costs in 2004 increased$13.1 million as compared with 2003 (combined). Theincrease was caused by various factors. We increasedsubstantially our effort in several areas including internalaudit, internal control and compliance; business development andbusiness improvement projects; and human resources. Our sellingcosts increased because our multi-client late sales increasedsubstantially. We incurred increased bonus expenses to a broadcategory of employees due to achievement of key performanceindicators under the bonus program that we established for 2004.Also, a weakening of the U.S. dollar increased our reportedcosts.***Impairment of Long-Lived Assets***     Since we generally evaluate our multi-client library on asurvey-by-survey basis at the end of each year, we expect towrite down the value of some surveys each year due to surveyspecific factors. In 2005 and 2004, we reported no impairmentsrelated to the multi-client library since we classified asamortization, rather than impairments, $15.0 million and$19.9 million, respectively, in write downs of individualsurveys that related to individual survey-specific factors andthat were not individually material. In 2005 we recognized animpairment charge of $4.6 million related to our decisionto convert the vessels used in our seafloor 4C operationsto towed streamer operations.     In the first ten months (Predecessor) of 2003, we hadimpairments of $95.0 million, which included$90.0 million of impairment of multi-client library and$5.0 million of impairments related to other assets andequipment.
48

Table of Contents
***Gain on Sale of Subsidiaries, Net***     In 2005, we recognized $156.4 million of net gains on thesale of subsidiaries. This primarily related to the sale ofPertra with a gain of $157.9 million, partially offset byloss of $1.5 million on the sale of our Norwegian ReservoirServices subsidiary. We had no such gains in 2004 or 2003.***Other Operating (Income) Expense, Net***     We recorded other operating income, net, of $26.1 millionin 2005. The amount includes a gain of $17.2 million fromthe release of liabilities related to our UK leases (asdescribed in further detail in the section“— Liquidity and Capital Resources — UKLeases” below) and a gain of $8.9 million from thesuccessful resolution of a claim against an equipment supplier.In 2004 we recorded other operating expense, net, of$8.1 million, primarily relating to costs to complete the2002 U.S. GAAP consolidated financial statements and there-audit of our U.S. GAAP financial statements for the yearended December 31, 2001. In 2003 (combined) werecorded other operating expense, net, of $22.4 million,primarily relating to severance payments that aggregated$19.8 million.***Interest Expense and Other Financial Items***     Interest expense for 2005 amounted to $96.4 million, areduction of $14.4 million from 2004. The decrease reflectsa significant reduction of interest-bearing debt and capitalleases between the two periods. Interest expense for 2004totaled $110.8 million compared to $99.0 million forthe first ten months (Predecessor) and $16.9 million forthe last two months (Successor) of 2003. Our average interestbearing debt was significantly lower in 2004 compared to 2003,but in 2003 most of our debt did not accrue interest forapproximately 100 days while we were in Chapter 11proceedings.     Income from associated companies totaled $0.3 million in2005 compared to $0.7 million in 2004 and $1.0 millionin 2003 (combined).     Other financial items, net, amounted to income of$5.9 million in 2005 compared to an expense of$10.9 million in 2004. The improvement of$16.8 million primarily relates to a foreign exchange gainof $4.1 million in 2005 compared to a loss of$8.0 million in 2004. Interest income increased by$2.6 million and we received a consent fee of$3 million in 2005 for certain changes to our UK leases. In2004, we had other financial expenses of $10.9 million in2004 compared to an expense of $5.7 million in 2003(combined).     In 2005, we completed a refinancing of a substantial portion ofour long-term debt and credit facilities and in particular thenotes we issued in the 2003 financial restructuring. In March2005, we redeemed $175 million of the $250 million8% Senior Notes due 2006 at 102% of par value. In Novemberwe redeemed the remaining $75 million of the notes at 101%of par value. In December we completed a tender offer andconsent solicitation for the $746 million 10% SeniorNotes due 2010. As a result, approximately $741.3 millionaggregate principal amount of the notes were retired at a priceof 113.64% of par value. The total cost of the refinancing, netof the aggregate amount of new debt incurred, was$107.3 million, including repayment premiums and expenses.This amount was charged to expense in 2005 and classified asdebt redemption and refinancing cost. We did not incur anycomparable costs for 2004 or 2003.***Reorganization Items***     In connection with our Chapter 11 reorganization, which wecompleted in 2003, we recorded reorganization items in ourconsolidated statement of operations totaling $3.5 millionin expenses for 2004 and the following items in 2003: •     for the first ten months (Predecessor) we recorded a gain on    debt discharge of $1,253.9 million and costs of    reorganization of $52.3 million;  •     for the last two months (Successor) we recorded    $3.3 million in costs of reorganization; and  •     for the first ten months (Predecessor) we recorded the net    effect at November 1, 2003, of adopting fresh start    reporting of $532.3 million. This amount represents the net    effect of differences between the
49

Table of Contents
     fair value of our assets and liabilities as measured at    November 1, 2003 and the carrying value of those assets and    liabilities immediately before adoption of fresh start reporting.     We describe our financial restructuring in more detail under“— 2003 Financial Restructuring” above andin note 3 of the notes to our consolidated financialstatements included in Item 18 of this annual report. Wedescribe our adoption of fresh start reporting in more detailunder “— 2003 Fresh Start Reporting and Changesin Accounting Policies” above and in note 3 of thenotes to our consolidated financial statements included inItem 18 of this annual report.***Income Tax Expense***     Income tax expense was $21.8 million in 2005 compared with$48.0 million in 2004 and $18.1 million in 2003(combined), excluding tax relating to discontinued operationsand the adoption of fresh start reporting. Tax expenses in 2005included current taxes of $10.8 million and net deferredtax expenses of $11.0 million. Taxes payable relatedprimarily to foreign taxes in regions where we are subject towithholding taxes or deemed to have a permanent establishmentand where we had no carryover losses. Current taxes included$2.7 million in income related to tax contingencies.     At December 31, 2005, we had a total of $623 millionof deferred tax assets (net of deferred tax liabilities) indifferent jurisdictions, predominantly in Norway and the UK. Atadoption of fresh-start reporting on November 1, 2003 andat December 31, 2004, we established valuation allowancesfor all of our deferred tax assets, with the exception of taxassets relating to Pertra. A valuation allowance, by taxjurisdiction, is established when it is more likely than notthat all or some portion of the deferred tax assets will not berealized. The valuation allowance is periodically adjusted basedupon the available evidence. During 2005, we concluded thatcertain valuation allowances are no longer necessary asavailable evidence, including recent profits and estimates ofprojected near term future taxable income, supported a morelikely than not conclusion that the related deferred tax assetswould be realized. As a result, in 2005 we released a portion ofthe valuation allowance, resulting in the recognition of adeferred tax asset of $20 million in the balance sheet atDecember 31, 2005. For more information about how weevaluate the need for valuation allowances related to deferredtax assets, including the effects of realizing the benefits ofdeferred tax assets for which a valuation allowance wasestablished at the adoption of fresh start reporting, pleaseread note 21 of the consolidated financial statementsincluded in Item 18 of this annual report.     Tax expenses in 2004 included current taxes of$20.8 million and net deferred tax expenses of$27.2 million. Current taxes included a $9.5 millioncharge related to tax contingencies. Deferred tax expenserelated primarily to Pertra where we made a full deduction ofcapital expenditures for tax purposes in the year these wereincurred. Pertra was subject to petroleum taxation rules inNorway at a nominal tax rate of 78%, where we could not offsetits income against losses from other operations.     Tax expenses in 2003 included current taxes of$24.0 million and net deferred tax benefits of$5.9 million.***Discontinued Operations***     In 2005, we recognized income from discontinued operations, netof tax, of $0.5 million relating to the sale of ourProduction Services subsidiary in 2002. In 2004, we recognizedincome from discontinued operations, net of tax, of$3.0 million relating to the same subsidiary. In 2003, lossfrom discontinued operations, net of tax, amounted to$2.3 million for the first ten months (Predecessor) and$0.1 million for the last two months (Successor).***Operating Profit (Loss) and Net Income (Loss)***     Operating profit for 2005 was $335.4 million, compared to aprofit of $35.7 million for 2004. In 2003 we recorded aprofit of $9.8 million for the first ten months(Predecessor) of 2003, which included impairment charges of$95.0 million, and a profit of $10.7 million for thelast two months (Successor) of 2003.     We reported net income of $112.6 million for 2005, comparedto a net loss of $134.7 million for 2004. For 2003 wereported net income of $557.0 million for the first tenmonths (Predecessor) and a net loss of
50

Table of Contents
$10.0 million for the last two months (Successor). Asdescribed above, net income for the first ten months of 2003 issignificantly impacted by the effects of our financialreorganization, including a gain on debt discharge of$1,253.9 million, adoption of fresh start reporting($532.3 million), and impairment charges($95.0 million).***Segment Operating Profit***     Segment operating profit is an integral part of how we monitorthe performance of our businesses. A reconciliation of operatingprofit/(loss) for 2005 and segment operating profit by year arepresented in the tables below. The individual reconciling itemsare discussed in separate paragraphs above. Please readNote 27 to our consolidated financial statements includedin Item 18 of this annual report for a reconciliation ofsegment operating profit to income (loss) before income taxexpense (benefit) and minority interest.                           **Net (Gain)** **Impairment of** **Segment**  **Operating** **Other Operating** **on Sale of** **Long-Lived** **Operating****2005** **Profit/(Loss)** **(Income)/Expense** **Subsidiaries** **Assets** **Profit**             **(In thousands of dollars)****Marine Geophysical** $154,501  $(8,847) $—  $4,575  $150,229 **Onshore**  (9,803)  —   —   —   (9,803)**Production**  43,491   —   —   —   43,491 **Pertra**  (1,507)  —   —   —   (1,507)**Reservoir/ Shared Services/ Corporate**  147,841   (17,248) $(156,382)  —   (25,789)**Elimination**  924   —   —   —   924                 **Total** $335,447  $(26,095) $(156,382) $4,575  $157,545                                          **Predecessor**    **Successor Company** **Company** **Combined**           **Two Months** **Ten Months** **Twelve Months**  **Years Ended December 31,** **Ended** **Ended** **Ended**    **December 31,** **October 31,** **December 31,****Segment Operating Profit** **2005** **2004** **2003** **2003** **2003**             **(In thousands of dollars, except percentage data)****Marine Geophysical** $150,229  $(34,980) $1,772  $41,782  $43,554 **Onshore**  (9,803)  (4,535)  1,778   19,741   21,519 **Production**  43,491   77,769   11,878   66,876   78,754 **Pertra**  (1,507)  28,120   (3,198)  17,236   14,038 **Reservoir/ Shared Services/ Corporate**  (25,789)  (20,986)  (476)  (19,475)  (19,951)**Elimination**  924   (1,593)  —   —   —                 **Total** $157,545  $43,795  $11,754  $126,160  $137,914                      *Marine Geophysical —*Marine Geophysicalreported a segment operating profit of $150.2 million in2005 compared to a loss of $35.0 million in 2004. Thisimprovement was primarily driven by a significant improvement incontract performance and lower multi-client amortization rates(see “ — Depreciation, Depletion andAmortization” above).     Marine Geophysical reported a segment operating loss of$35.0 million in 2004 compared to a profit of$43.6 million in 2003. This was driven primarily by weakerperformance in the contract market, especially in the first halfof 2004 when we experienced weak prices, operating disturbancesand higher costs of sales.     *Onshore —*Onshore recorded a segment operatingloss of $9.8 million in 2005 compared to a loss of$4.5 million in 2004. The weak result, despite increasedrevenues, relates primarily to mobilization andstart-up costs forprojects at the end of 2005. Onshore is expected to realizestrong results in the first half of 2006 because a significantportion of mobilization costs on large projects have beenrecognized in 2005, while most of the revenue generatingactivities will be performed in 2006. Compared to the Onshoresegment
51

Table of Contents
operating profit of $21.5 million in 2003, we saw a declineby $26.0 million in 2004, which was primarily due to areduction of activity on profitable contracts in South America.     *Production —*Production recorded a segmentoperating profit of $43.5 million in 2005, which representsa reduction of $34.3 million from 2004. This reduction wascaused by a combination of a reduction of revenues from allvessels except *Petrojarl Varg*and increased costs. For2003, the segment operating profit was $78.8 million, whichwas 1% higher than 2004.     *Pertra —*Pertra recorded a segment operatingloss of $1.5 million for two months of operations in2005, compared to full year profit of $28.1 million for2004 and $14.0 million for 2003.     For more information regarding segment operating profit, pleasesee Note 27 to our consolidated financial statementsincluded in Item 18 of this annual report.**Outlook; Factors Affecting Our Future Operating Results**     Our future operating results will depend on numerous factors,including those described under “KeyInformation — Risk Factors” in Item 3 ofthis annual report. Factors that will impact our futureoperating results include, but are not limited to, the following: •     our ability to complete a separation of our geophysical and    productions businesses;  •     the development of our main market drivers, which includes    prices and price expectations for oil and natural gas. Such    prices and price expectations affect the demand for exploration    and production related seismic services and the economics in    developing and producing small and medium sized oil and natural    gas fields;  •     our ability to optimize performance of our FPSO vessels and    profitably expand the Production segment, including, among    others: •     sustaining high regularity and uptime;  •     maximizing volumes and revenues under current contracts,    including further extension of contract duration where    appropriate; and  •     capturing new profitable contract opportunities and achieving    timely redeployment of vessels on terms and at volumes    reflecting their production capacities; •     the business performance of our Onshore and Marine Geophysical    segments, including, among others: •     the demand for contract seismic services, coupled with    (a) our ability to benefit from our strong    HD3Dsm    position and high productivity and vessel performance,    (b) our ability to reduce steaming and other unproductive    vessel time, and (c) the prices for our services;  •     demand for multi-client seismic data in various geographic    regions, including future licensing rounds and demand for data    offshore Brazil;  •     our ability to profitably rebuild new multi-client seismic    survey activity to complement our contract work; and  •     implementation of our streamer expansion and replacement program    for our seismic vessels; •     foreign currency exchange rate fluctuations between the    U.S. dollar, our functional currency, and the Norwegian    kroner or the British pound, which will generally have an impact    on our operating profit because we have significant operating    expenses in Norwegian kroner and British pounds;  •     the extent to which we participate in strategic acquisitions or    dispositions of assets or businesses or in one or more joint    ventures involving such assets or businesses; and  •     our ability to continue to develop or acquire competitive    technological solutions for our different business units.
52

Table of Contents
     The markets in which we operate showed strong improvement in2005. Oil prices remained at high levels, and oil companiesincreased their exploration and production (E&P) spending.E&P spending is expected to increase further in 2006 and, inthe medium to long term, high oil price levels are expected topositively impact our core markets.     The global marine seismic fleet was at full capacity utilizationin 2005. We believe that demand will increase further in 2006,outweighing increase of marine seismic capacity and resulting infurther improved prices. Within floating production, increasedfocus on smaller fields and tail-end optimization forms a basisfor growth in outsourcing where our floating production activityis well positioned with market leadership in the North Sea andthe potential to grow in selected international markets.     In 2006, we expect the following factors to influence ourperformance:***Marine Geophysical*** •     Marine 3D industry seismic fleet at full capacity utilization    with our streamer contract operating profit margins expected to    improve by more than 10 percentage points compared to full    year 2005, assuming that we do not experience any unexpected    significant increase in operating costs or any significant    operating disturbances relating to our contract operations;  •     Multi-client late sales expected to be lower than 2005 as a    result of low levels of investments in recent years; and  •     Cash investments in multi-client library expected to double from    an investment of $46 million in 2005, with continued high    pre-funding levels.***Onshore*** •     Revenues and operating profit expected to be significantly above    2005 levels; and  •     Cash investments in multi-client library expected to more than    double from an investment of $8 million in 2005.***Production*** •     Revenues expected to be slightly lower than full year    2005; and  •     Operating expenses, including maintenance, expected to be in    line with 2005.     For a discussion regarding our expected capital expenditures in2006, please see “Liquidity and CapitalResources — Capital Requirements and Commitments”below.**Liquidity and Capital Resources*****Liquidity — General***     We believe that our cash balances and our available borrowingcapacity under the credit agreement established in December 2005will be adequate to meet our working capital and liquidity needsfor the remainder of 2006 and 2007. While we believe that wehave adequate sources of funds to meet our liquidity needs forthe 2006-2007 period, our ability to meet our obligations in thelonger term depends on our future performance, which, in turn,is subject to many factors beyond our control. See “KeyInformation — Risk Factors” in Item 3 ofthis annual report.***Sources of Liquidity — Capital Resources***     Our internal sources of liquidity are cash and cash equivalentsand cash flow from operations. Cash and cash equivalents totaled$121.5 million at December 31, 2005, compared to$132.9 million at December 31, 2004.
53

Table of Contents
     Net cash provided by operating activities totaled$279.1 million in 2005, compared to $282.4 million in2004. In 2005, accounts receivable increased by$52.3 million, after an increase in revenues by$66.8 million in 2005 compared to 2004, while accountspayable decreased by $7.6 million. Generally, oursubsidiaries are not subject to restrictions on their ability totransfer funds to us that would materially affect our ability tomeet our cash obligations.     In December 2005, we entered into a new credit agreement,establishing a term loan of $850 million (“TermLoan”) and a revolving credit facility (“RCF”) of$150 million. The Term Loan amortizes 1% per annumwith the remaining balance due in 2012, and bears interest at arate of the London Interbank Offered Rate (“LIBOR”)plus a margin that depends on our leverage ratio. For purposesof the credit agreement, leverage ratio is the ratio ofconsolidated indebtedness to consolidated EBITDA, as defined inthe credit agreement, reduced by multi-client investments madefor the period in question. At a leverage ratio of 2.25:1 orgreater, the applicable margin will be 2.5% per annum.Below that level, the margin will be 2.25% per annum. Weare required to make principal repayments at a minimum level of0.25% of the initial principal amount of the Term Loan perquarter. The credit agreement contains provisions that generallyrequire us to apply 50% of excess cash flow to repay outstandingborrowings for periods when our leverage ratio exceeds 2:1. Wecan make optional payments to reduce the principal at nopenalty. Excess cash flow for any period is defined as net cashflow provided by operating activities during that period lesscapital expenditures made in that period or committed to be madein the next period, less debt service payments and less accruedincome taxes to be paid in the next period. The Term Loan is anobligation of PGS ASA and PGS Finance Inc. as co-borrower, andis secured by pledges of shares of certain material subsidiariesand guaranteed by certain material subsidiaries.     The credit agreement also establishes the RCF. We may borrowU.S. dollars, or any other currency freely available in theLondon banking market to which the lenders have given priorconsent, under the RCF for working capital and for generalcorporate purposes. Up to $60 million of the RCF can beused for letters of credit. Letters of credit, which can beobtained in various currencies, can be used to secure, amongother things, performance and bid bonds required in our ongoingbusiness. The RCF is secured by pledges of shares of materialsubsidiaries. The RCF matures in 2010. Borrowings under the RCFbear interest at a rate of LIBOR plus a margin that depends onour leverage ratio. At a leverage ratio of 2.25:1 or greater,the applicable margin will be 2.25%; at a ratio between 2:1 and2.25:1, the applicable margin will be 2.00%; and at a ratiobelow 2:1, the applicable margin will be 1.75. AtDecember 31, 2005, $14.6 million of letters of creditwere issued under the RCF.     In February 2005 we established an overdraft facility on NOK50 million as part of our Norwegian cash poolingarrangement.     Our external sources of liquidity include the $150 millionrevolving credit facility established in December 2005 as partof our $1 billion senior secured revolving credit facilitydescribed above. As of December 31, 2005, we had unusedborrowing capacity of $135.4 million under the revolvingcredit facility. Ongoing trade credit will also be a source ofliquidity. Subject to market conditions and other factors, wemight also seek to raise additional debt or equity in thecapital markets.     The book value of our debt, including capital leases, wasapproximately $980 million as of December 31, 2005compared to approximately $1,164 million atDecember 31, 2004.     Our debt consisted of the following primary components atDecember 31, 2005:        **(In millions of dollars)**    10% Senior Notes, due 2010 $5     8.28% First Preferred Mortgage Notes, due 2011  88     Term loan due 2012  850     Other loans due 2006  3          Total debt $946         Capital leases  34          Total $980     
54

Table of Contents
     Net interest bearing debt (interest bearing debt, includingcapital leases, less cash and cash equivalents, restricted cashand interest bearing investments) was approximately$829 million as of December 31, 2005 compared to$995 million as of December 31, 2004.     Our December 2005 credit facility contains financial covenantsand negative covenants that restrict us in various ways. Thefacility provides that •     our total leverage ratio may not exceed 3.50 to 1.0 in 2006,    3.25 to 1.0 in 2007 and 3.00 to 1.0 in 2008 and may not exceed    3.00 to 1.0 at the time of our proposed separation transaction    described under “Information on the Company —    Proposed Separation of the Geophysical and Production    Businesses” in Item 4 of this annual report  •     our consolidated interest coverage ratio (defined as the ratio    of consolidated EBITDA, as defined in the credit agreement,    reduced by multi-client investments to consolidated interest    expense) must be at least 3.0 to 1.0, and  •     our consolidated fixed charge coverage ratio (defined as the    ratio of consolidated EBITDA, as defined in the credit    agreement, reduced by multi-client investments to consolidated    fixed charges) must be at least 1.3 to 1.0.     In addition, the credit agreement restricts our ability, amongother things, to sell assets; incur additional indebtedness orissue preferred stock; prepay interest and principal on ourother indebtedness; pay dividends and distributions orrepurchase our capital stock; create liens on assets; makeinvestments, loans, guarantees or advances; make acquisitions;engage in mergers or consolidations; enter into sale andleaseback transactions; engage in transactions with affiliates;amend material agreements governing our indebtedness; change ourbusiness; enter into agreements that restrict dividends fromsubsidiaries; and enter into speculative financial derivativeagreements.     We experience some seasonality in our business, and our capitalrequirements may be impacted by this seasonality. For moreinformation relating to the seasonality of our business, see“— Seasonality” above.     For further information relating to our indebtedness as ofDecember 31, 2005 and the maturities of such indebtedness,please read note 16 of the notes to our consolidatedfinancial statements in Item 18 of this annual report.***Net Cash Used in or Provided by Investing and Financing    Activities***     Net cash provided by investing activities totaled$10.5 million in 2005, compared to net cash used of$183.4 million in 2004. The change of $193.9 millionwas primarily due to (a) $155.4 million in netproceeds from the sale of Pertra and additional considerationrelating to the sale of Production Services in 2002, (b) adecrease in capital expenditures of $57.9 million, offsetin part by (c) a $14.6 million increase in investmentin multi-client library.     The large decrease in capital expenditures reflects thedivestment of Pertra, which had capital expenditures of$85.0 million in 2004 compared to $0.1 millionreflected in the first two months of 2005 in which it was a partof our company. The other business areas had an increase incapital expenditures of $27.0 million, mainly divided intoMarine Geophysical ($15.3 million) and Onshore($11.2 million). The increases are mainly due to increasedcapital expenditures on our streamer replacement and expansionprogram in Marine Geophysical and more normal spending onseismic equipment in Onshore after a very low level in 2004.     Net cash used in financing activities totaled$301.0 million in 2005., compared to $71.3 million in2004. In 2005, we made net repayments of long-term debt andprincipal payments under capital leases totaling$184.9 million, compared to net repayments in 2004 of$47.1 million. In 2004 we made a $22.7 milliondistribution of excess cash to creditors in connection with our2003 financial restructuring, with no similar distributionduring 2005.     In 2005 we repaid all of our $250 million 8% SeniorNotes at a redemption premium totaling $4.3 million. Wealso repaid $741.3 million of the $745.9 million10% Senior Notes at a tender and consent premium of
55

Table of Contents
$101.2 million. Costs associated with refinancing thelong-term debt were approximately $9.9 million, capitalizedas deferred debt issue costs.***Capital Requirements and Commitments***     Our capital requirements are affected primarily by our resultsof operations, capital expenditures, investment in multi-clientlibrary, debt service requirements, lease obligations, workingcapital needs and outcome of significant contingencies. Themajority of our ongoing capital requirements, other than debtservice, lease obligations and contingencies, consist of: •     capital expenditures on seismic vessels and equipment, including    data processing equipment and streamers;  •     investments in our multi-client library; and  •     working capital related to growth, seasonality and specific    project requirements.     Since we sold our oil and natural gas subsidiary Pertra in March2005, we do not have any ongoing capital requirements related tothese operations. We had substantial capital expenditures inPertra in 2004.     In prior years, our capital expenditures have related not onlyto normal ongoing equipment replacement and refurbishment needs,but also to increases in our seismic data acquisition capacityand in our FPSO operations. Such expenditures, which can besubstantial from time to time, depend to a large extent upon thenature and extent of future commitments that are largelydiscretionary. In 2005 we accelerated the replacement ofstreamers and at the same time expanded streamer capacity inMarine Geophysical. In Onshore we increased the spending onseismic equipment from a low level in 2004.     The following table sets forth our consolidated capitalexpenditures in 2005, 2004 and 2003:              **Business Segments** **2005** **2004** **2003**         **(In million of dollars)**    Marine Geophysical $72.2  $56.9  $16.1     Onshore  12.6   1.4   7.0     Production  —   1.0   0.5     Other  5.6   4.1   0.3     Pertra  0.1   85.0   34.2                Total  90.5   148.4   58.1               Investments in multi-client library $55.7  $41.1  $90.6                For 2006, we expect: •     to approximately double our cash investment in our Marine    Geophysical multi-client library from an investment of    $46 million in 2005, with continued high pre-funding    levels, and approximately double the cash investment in our    Onshore multi-client library from an investment of    $8 million in 2005;  •     capital expenditures, in addition to the investment in the new    Ramform seismic vessel newbuild described below, of    $90-100 million in    Marine Geophysical, primarily related to our streamer expansion    and replacement program, and of approximately $10 million    in Onshore; and  •     capital expenditures in Production on our existing vessels to    continue at a low level because our FPSO vessels are not    expected to have substantial replacement needs through 2006.     In 2006, we acquired the tanker *Rita Knutsen*to haveavailable for later conversion to an FPSO. The acquisition costfor the tanker of $35 million was paid in January and March2006. The capital expenditures for a conversion into an FPSOwill be substantial and will depend on the particular project.
56

Table of Contents
     Under our current streamer expansion, upgrade and replacementprogram, we expect to spend approximately $50 million onmarine seismic streamers in 2006 and approximately$30 million to $35 million per year in the period 2007to 2010. Since this program is discretionary, however, we may inthe future change the scope and annual capital expenditurerelated to the program. We also intend to make maintenance andrefurbishment expenditures as required so as to maintain ourfleet of marine seismic and FPSO vessels in good working order.We intend to make other capital expenditures in our businesssegments as conditions dictate and financial resources permit.Finally, we may also incur capital expenditure significantlyabove the amounts described above to pursue new businessopportunities for any of our business segments.     In March 2006, we announced that we intend to build a new thirdgeneration Ramform seismic vessel at Aker Yards, Langsten,Norway. We currently expect delivery in the first quarter 2008.We expect the new vessel to cost approximately $85 million,excluding the cost of seismic equipment, and we expect the totalcost to be approximately $160 million, excluding projectmanagement cost and interest. Payments to the yard will be madein five equal installments, with two due in 2006, two due 2007,and the final payment due upon delivery of the vessel, which isexpected in 2008. Payments for seismic equipment will be madeover this payment period. The total payments relating to thenewbuild project in 2006 are estimated to be approximately$55 million.***Off-Balance Sheet Arrangements***     For a discussion of our UK leases, see “ — UKLeases” below.***Long-Term Contractual Obligations***     The following table presents our long-term contractualobligations related to our loan and lease agreements and otherlong-term liabilities and related payments due in total and byperiod as of December 31, 2005:                          **Payments Due by Period**         **Contractual Obligations** **Total** **2006** **2007-2008** **2009-2010** **Thereafter**             **(In million of dollars)**    Long-term debt obligations $943.9  $21.7  $43.9  $53.2  $825.1     Operating lease obligations(b)  158.5   39.2   54.2   37.2   27.9     Capital lease obligations  33.7   20.5   13.2   —   —     Other long-term liabilities(a)  103.5   15.7   29.6   22.8   35.4                      Total $1,239.6  $97.1  $140.9  $113.2  $888.4                  (a)     Excluding other long-term liabilities that are contingent and    not determinable with respect to the timing of future payments    (see the table below captioned “Other Long-Term    Liabilities”). (b)     Included in the minimum lease commitment for FPSO shuttle and    storage tankers as presented in the table above is charter hire    for the six month cancellation period for a storage tanker    operating on the Banff field in the North Sea. We are required    to charter the vessel for as long as the *Ramform Banff*produces the Banff field, which could extend to 2014    depending on the customer/field operator. The maximum payment    for the charter through 2014 is $97.8 million.     For additional information about the components of our long-termdebt and lease obligations, please refer to notes 16 and 20to the consolidated financial statements included inItem 18 of this annual report.     The table below is provided to illustrate the expected timing offuture payments related to other long term-liabilities reportedin our consolidated balance sheet as of December 31, 2005.Determining the expected future cash flow presented in the tablerequires us to make estimates and assumptions since the timingof any payments related to these long-term liabilities generallyis not fixed and determinable but rather depends on futureevents. We believe that our estimates and assumptions arereasonable, but actual results may vary from
57

Table of Contents
what we have estimated or assumed. As a result, our reportedliabilities and expenses could be materially affected if theassumptions and estimates we have made were changedsignificantly.                               **Payments Due by Period**             **Other Long-Term Liabilities** **Total** **2006** **2007-2008** **2009-2010** **Thereafter** **Not Determinable**               **(In millions of dollars)**    Other long-term liabilities:                             Pension liability(a) $45.4  $7.0  $14.0  $8.7  $15.7  $—      Asset removal obligation(b)  20.0   0.3   —   —   19.7   —      Accrued liabilities related to our UK leases:                              — related to interest rate differential(c)  38.1   8.4   15.6   14.1   —   —       — related to tax indemnifications  12.7   —   —   —   —   12.7      Tax contingencies  19.2   —   —   —   —   19.2      Other  5.4   —   —   —   —   5.4                          Total $140.8  $15.7  $29.6  $22.8  $35.4  $37.3                     (a)     We have projected benefit plans in Norway and in UK. Pension    liability represents the aggregate shortfall of pension plan    assets compared to projected benefit obligations for our plans,    as recognized in our consolidated balance sheet. We will pay    this obligation over time, as adjusted for changes in estimates    relating to obligations and assets, in accordance with the    funding requirements of the life insurance companies through    which we fund our plans in Norway and in accordance with the    funding practice that we agree with the trustees of our pension    scheme in UK. Such requirements are subject to change over time,    but we expect these payments to be made over several years.    (b)    Asset removal obligation as of December 31, 2005 primarily    relates to the *Ramform Banff*operations.     (c)    The estimated net present value of future payments related to    interest rate differential on our UK leases as of    December 31, 2005 is $54.5 million based on forward    interest rate curves, which is $16.4 million higher than    the amount included in accrued liabilities from    fresh-start reporting.    Payments through the year 2008 reflect estimated total payments    based on forward interest rate curves as of December 31,    2005. The amount presented for 2009-2010 is the residual amount.***UK Leases***     We entered into capital leases from 1996 to 1998 relating to*Ramform Challenger, Valiant, Viking, Victory*and*Vanguard*; the FPSO *Petrojarl Foinaven*; and theproduction equipment for the *Ramform Banff*. The terms forthe leases range from13-25 years. Wehave indemnified the lessors for the tax consequences resultingfrom changes in tax laws or interpretations thereof or adverserulings by the tax authorities and for variations in actualinterest rates from those assumed in the leases. There are nolimits on either of these indemnities.     The lessors claim tax depreciation (capital allowances) on thecapital expenditures that were incurred for the acquisition ofthe leased assets. Although the UK Inland Revenue generallydeferred for a period of time agreeing to the capital allowancesclaimed under such leases pending the outcome of a legalproceeding in which the Inland Revenue was challenging capitalallowances associated with a defeased lease, in November 2004,the highest UK court of appeal ruled in favor of the taxpayerand rejected the position of the Inland Revenue. In connectionwith the adoption of fresh start reporting on November 1,2003 and before the November 2004 ruling, we recorded aliability of 16.7 million British pounds (approximately$28.3 million). We release applicable portions of thisliability if and when the Inland Revenue accepts thelessors’ claims for capital allowances under each lease. In2005 we released 9.4 million British pounds (approximately$17.2 million) of the liability.
58

Table of Contents
     The remaining accrued liability at December 31, 2005 of7.3 million British pounds (approximately$12.7 million) relates to the *Petrojarl Foinaven*lease where the Inland Revenue has raised a separate issue aboutthe accelerated rate at which tax depreciation is available. Ifthe Inland Revenue were successful in challenging that rate, thelessor would be liable for increased taxes on *PetrojarlFoinaven*in early periods (and decreased taxes in lateryears), and our rentals would increase. How much the rentalscould increase depends primarily on how much of the asset willbe subject to a different depreciation rate. Management believesthat 60 million to 70 million British pounds(approximately $104 million to $121 million)represents a worst case scenario for this liability.     The leases are legally defeased because we have made payments toindependent third-party banks in consideration for which thesebanks have assumed liability to the lessors equal to basicrentals and termination sum obligations. The defeased rentalpayments are based on assumed Sterling LIBOR rates between 8%and 9% per annum. If actual interest rates are greater than theassumed interest rates, we receive rental rebates. Conversely,if actual interest rates are less than the assumed interestrates, we pay rentals in excess of the defeased rental payments.Over the last several years, the actual interest rates have beenbelow the assumed interest rates. Prior to November 1,2003, we had deferred a portion of a deferred gain representingthe net present value of additional required rental payments asof the inception of each lease. Such deferred gain was amortizedover the terms of the leases. Effective November 1, 2003,we adopted fresh start reporting, and recorded a liability equalto the fair value of the future additional required rentalpayments based on forward market rates for Sterling LIBOR and an8% discount rate. This liability, which is amortized based onfuture rental payments, amounted to 30.5 million Britishpounds (approximately $51.6 million) at November 1,2003, 24.6 million British pounds (approximately$47.2 million) at December 31, 2004 and22.0 million British pounds (approximately$38.1 million) at December 31, 2005.     Currently, interest rates are below the assumed interest rates.Based on forward market rates for Sterling LIBOR, the netpresent value, using an 8% discount rate, of the additionalrequired rental payments aggregated 31.5 million Britishpounds (approximately $54.5 million) as ofDecember 31, 2005. Of this amount, 1.2 million Britishpounds (approximately $2.0 million) was accrued atDecember 31, 2005, in addition to the remaining fresh startliability as described above.     Additional required rental payments were $7.2 million foreach of the years ended December 31, 2005 and 2004,$4.9 million for the two months ended December 31,2003 (Successor) and $1.5 million for the ten months endedOctober 31, 2003 (Predecessor).     For additional information regarding our UK leases, please seenotes 2 and 20 of the notes to our consolidated financialstatements included in Item 18 of this annual report.**Research and Development**     We incurred research and development costs of $9.9 million,$3.4 million and $2.6 million during the years endedDecember 31, 2005, 2004 and 2003, respectively. Foradditional information regarding our research and developmentpolicies and expenditures, please see “Information on theCompany — Other Factors Related to OurBusiness — Our Research and Product Development”in Item 4 and our consolidated statements of operations inItem 18 of this annual report.
59

Table of Contents
**ITEM 6.*****Directors, Senior Management and Employees*****Board of Directors**     The table below provides information about our directors as ofMarch 31, 2006:                     **Director** **Term** **Share****Name (Age)** **Position** **Since** **Expires(a)** **Ownership**             Jens Ulltveit-Moe(63)  Chairman   2002   2006   3,087,332     Keith Henry(61)  Vice Chairman   2003   2006   —     Francis Gugen(57)  Director   2003   2006   —     Harald Norvik(59)  Director   2003   2006   —     Rolf Erik Rolfsen(65)  Director   2002   2006   —     Clare Spottiswoode(53)  Director   2003   2006   —     Anthony Tripodo(53)  Director   2003   2006   —  (a)     The annual general meeting is scheduled to occur on    June 14, 2006     *Mr. Ulltveit-Moe*has been our chairman of the Boardof Directors since September 2002. He is the founder and hasbeen president and chief executive officer of Umoe AS, ashipping and industry company, since 1984. From 2000 to 2004, hewas the president of the Confederation of Norwegian Business andIndustry. From 1980 to 1984, Mr. Ulltveit-Moe served asmanaging director of Knutsen OAS. From 1972 to 1980, he wasmanaging director of the tanker division of SHV Corporation.From 1968 to 1972, Mr. Ulltveit-Moe was an associate withMcKinsey & Company, Inc. in New York and London.Mr. Ulltveit-Moe holds a master’s degree in businessadministration from the Norwegian School of Economics andBusiness Administration and a master’s degree ininternational affairs from the School of International Affairs,Columbia University, New York.     *Mr. Henry*has been our vice chairman of the Board ofDirectors since October 2003. He served as group executive vicepresident for the Kvaerner Engineering and Construction Groupfrom March 2000 until June 2003. He was chief executive ofNational Power Plc from 1995 to 1999 and was chief executive ofBrown & Root Limited from 1990 to 1995. He is thesenior independent non-executive director at Burren Energy plcand at Emerald Energy Plc, and is a non-executive director ofSouth East Water Limited. He acts as an adviser to a number ofconstruction and energy related organizations. He holds BSc andMSc degrees, and is a Fellow of the Royal Academy of Engineering.     *Mr. Gugen*is currently active as a consultant and aninvestor in the energy industry. He served with Amerada HessCorporation for eighteen years, from 1982 to 2000, holdingvarious positions including chief executive of Amerada Hess UKfrom 1995 to 2000 and chief executive of northwestern Europefrom 1998 to 2000. Mr. Gugen acts as chairman andnon-executive director for various other companies, includingCH4 Energy Limited, Island Gas Limited and The BritanniaBuilding Society, where he also sits on the audit committee.Mr. Gugen has earlier worked for Arthur Andersen and is aUK chartered accountant.     *Mr. Norvik*is chairman and a partner of EconManagement, chairman of the Board of Directors for Oslo StockExchange, member of the Board of Directors in ConocoPhillips andchairman of the Supervisory Board in DnB NOR ASA. He served aschief executive officer of Statoil ASA from 1988 to 1999. He wasfinance director and a member of the executive board of the AkerGroup from 1981 to 1988. He served as personal secretary to thePrime Minister of Norway and as Deputy Minister in The Ministryof Petroleum and Energy from 1979 to 1981. Mr. Norvik has aMaster of Science Degree in Business from The Norwegian Schoolof Economics and Business Administration.     *Mr. Rolfsen*holds several board positions. He is amember of the board of directors of Technip S.A., Paris and Gazde France Norge A.S.. He is also chairman of the executivecouncil of the Industrial Development Fund at NTNU in Trondheim.From 1987 to 2000, he was managing director of TOTAL Norge A.S.and from 1999 to 2000 he was also managing director of FinaExploration Norway. From 1980 to 1986,
60

Table of Contents
he was executive vice president of Kongsberg Vapenfabrikk A.S..He was educated at the College of Commerce in Oslo.     *Ms. Spottiswoode*has been deputy chairman and seniornon-executive director at British Energy since June 2002, actsas chair of British Energy’s remuneration committee and hasserved as an independent director of that company since 2001.She currently acts as non-executive chair of the board ofEconomatters Ltd. and is a non-executive director ofBioFuels, Bergesen Worldwide Gas ASA and Tullow Oil plc.. She isalso a member of the board of the Department of HealthCommercial Advisory Board and a Policy Holder Advocate forAviva. She previously held several non-executive directorpositions including Booker plc.. She was director general ofOfgas, the UK Gas Regulation Organization, from 1993 to 1998. In1993 she served as a member of the UK Deregulation Task Force,and from 1998 to 2002 sat on the UK Public Services ProductivityPanel. Her career started as an economist with the HM Treasurybefore establishing her own software company. In 1999 she wasmade a Commander of the Order of the British Empire for servicesto industry, and holds degrees in economics from Cambridge andYale University.     *Mr. Tripodo*has been managing director of Arch CreekAdvisors LLC, an investment-banking firm, since 2003. He alsoserves as a non-executive director for Helix Energy SolutionsGroup, Inc. (formerly Cal Dive International) and VetcoInternational Limited, both oilfield service companies, based inHouston, Texas and London, England, respectively. From 1997 toApril 2003, Mr. Tripodo served at Veritas DGC in variouscapacities, including executive vice president and chieffinancial officer. He also has held various senior executive andfinancial roles at Baker Hughes and PricewaterhouseCoopers.Mr. Tripodo has a B.A. degree from St. Thomas University.**Committees**     Under Norwegian law, decision-making authority may not bedelegated by the Board of Directors to its committees orsubcommittees. The Board may, however, establish committees toassist it in discharging its responsibilities. Our Board ofDirectors has appointed two such committees, the audit committeeand the remuneration committee.     Our audit committee currently consists of three members,Messrs. Gugen (chairman), Norvik and Tripodo. The Board ofDirectors has determined that the members of the audit committeeare independent under applicable provisions of the SecuritiesExchange Act of 1934 and New York Stock Exchange listingstandards. Our audit committee has adopted a written charter, acopy of which we have filed as an exhibit to this annual report.     The audit committee acts to support the Board of Directors inthe administration and exercise of the Board’sresponsibility for supervisory oversight under applicableNorwegian and other laws and stock exchange listing standards inconnection with our financial statements and various audit,accounting and regulatory requirements. The audit committee isresponsible for proposing to the full Board, for presentationand election at our annual general meeting of shareholders, theindependent registered public accounting firm of our company.The audit committee is also responsible for supporting the Boardin the administration and exercise of the Board’sresponsibility for supervisory oversight in relation to, amongother items: •     financial statement and disclosure matters, including our    quarterly and annual financial statements and related    disclosures;  •     reviewing the quarterly and annual financial statements,    including reviewing major issues regarding accounting principles    and financial statement presentations, the adequacy of our    internal controls and discussing significant financial reporting    issues and judgments made in connection with preparation of the    financial statements;  •     provision by the auditor of audit services and permitted    non-audit services;  •     audits of our financial statements, including reviewing our    critical accounting policies and practices;  •     our relationship with our independent registered public    accounting firm, including the qualifications, performance and    independence of the auditors;
61

Table of Contents
 •     our internal audit function; and  •     responsibilities to comply with various legal and regulatory    requirements that could affect our financial statements.     The U.S. Securities Exchange Act of 1934 and the listingstandards of the New York Stock Exchange require the auditcommittee of a listed company in the United States, such as PGS,to be directly responsible for the appointment, compensation,retention and oversight of the work of that company’sindependent registered public accounting firm. Because underNorwegian law the power to appoint, retain and compensate theauditors is held by the shareholders, our audit committee isdirectly responsible only for the oversight of the work of theauditors and the audit committee and the full Board recommendthe appointment, retention and compensation of the auditors toits shareholders for approval. In addition, as a foreign privateissuer in the United States, we are not required to publish theaudit committee report required by applicable regulations of theSEC for U.S. domestic issuers.     Our remuneration committee consists of Messrs. Henry(chairman) and Rolfsen. The Board of Directors hasdetermined that the members of the remuneration committee areindependent under applicable New York Stock Exchange listingstandards. The remuneration committee supports the Board ofDirectors in the administration and exercise of the Board’sresponsibility for supervisory oversight of overall policy andstructure with respect to compensation and incentive matters,including compensation and incentive arrangements for our chiefexecutive officer and other senior executive officers. Ourremuneration committee has adopted a written charter, a copy ofwhich we have filed as an exhibit to this annual report. As aforeign private issuer in the United States, we are not requiredto publish the compensation committee report required byapplicable regulations of the SEC for U.S. domestic issuers.**Nomination Committee**     The members of the nomination committee are elected by ourshareholders in accordance with Norwegian corporate governancebest practices. The members of the committee, consisting ofRoger O’Neil, Hanne Harlem and C. Maury Devine, are notmembers of our board of directors. The nomination committee isresponsible for making recommendations for consideration by theshareholders relating to: •     individuals who are nominated to serve as members of the Board    of Directors and as the chairperson of the Board of Directors;  •     individuals who are nominated to serve as members of the    nomination committee and as the chairperson of the nomination    committee;  •     the remuneration of the directors and the members of the    nomination committee; and  •     any amendments of the nomination committee mandate and charter.     *Mr. O’Neil*is the chairperson of our nominationcommittee. He is a former executive of Mobil and executive vicepresident and member of the executive board of Statoil.Mr. O’Neil has worked as Senior Oil and Gas Advisor inthe Corporate Finance Group of Dresdner Kleinworth andWasserstein and as a consultant for The World Bank. He is amember of the board in Clearvision International, Pearl Energyand Upstream. Mr. O’Neil holds a BS in ChemicalEngineering from the University of Notre Dame and an MBA fromCornell University.     *Mrs. Harlem*has been University Director at theUniversity of Oslo since 2004 and was Minister of Justice inNorway from 2000 to 2001. She is presently chairperson of theboard in UniRand, and a member of the board in Gaz de France,Helse SÆr and Forskningsparken. Mrs. Harlem has a law degreefrom the University of Oslo.     *Ms. Devine*is a former ExxonMobil executive andformer Fellow at Harvard University’s Kennedy School ofGovernment Belfer Center for Science and International Affairs.She currently is member of the Board of Directors ofIndependence Air, Det Norske Veritas (DNV) and FMCTechnologies. Ms. Devine holds graduate degrees fromMiddlebury College and Harvard University.
62

Table of Contents
     The listing standards of the New York Stock Exchange requireU.S. listed companies to have a corporate governancecommittee (1) to develop and recommend to the board a setof corporate governance guidelines applicable to the listedcompany and (2) to oversee the evaluation of the board andmanagement. In accordance with Norwegian law and customarypractice, our Board of Directors, which is composed entirely ofnon-management directors, fulfills those responsibilities.**Corporate Governance**     We are committed to maintaining high standards of corporategovernance and believe that effective corporate governanceestablishes the framework by which we conduct ourselves indelivering services to our customers and value to ourshareholders. Although we are registered in Norway as a publiclimited company and our governance model is built on Norwegiancorporate law, we are subject to the requirements applicable toforeign private issuers in the United States, including thoseestablished by the SEC and the NYSE.     Our corporate governance principles are adopted and reviewedperiodically by the Board of Directors. The Corporate GovernancePrinciples, together with our Core Values and our Code ofConduct, Audit Committee Charter, Remuneration Committee Charterand our Rules of Procedure for the Board of Directors, areavailable under the “About PGS” section of ourinternet website at *www.pgs.com* and in print to anyshareholder who requests a copy. Requests should be directed toour investor relations department at ir@pgs.com.***Director Independence***     At its meeting held March 22, 2006, our Board of Directorsaffirmatively determined that each of Francis Gugen, KeithHenry, Harald Norvik, Rolf Erik Rolfsen, Clare Spottiswoode andAnthony Tripodo has no material relationship with us (eitherdirectly or as a partner, shareholder or officer of anorganization that has a relationship with us) and that each istherefore an “independent” director under applicableNYSE listing standards. These determinations were made by ourBoard of Directors based on representations made by each ofthose directors to us, a review of applicable NYSE rules andlisting standards and a review of our Rules of Procedures forthe Board of Directors.     Shareholders and other interested parties may communicatedirectly with our independent directors by sending a writtencommunication in an envelope addressed to “Board ofDirectors (Independent Members)” in care of our GeneralCounsel at the address indicated on the cover of this annualreport.***Meetings of Non-management Directors***     Our Board of Directors consists of only non-managementdirectors. As such, every meeting of our Board of Directors is ameeting of non-management directors. In addition, if the groupof non-management directors includes a director who is notindependent under NYSE listing standards, the independentdirectors will meet in executive session at least once annually.Currently, the director who presides at meetings of thenon-management directors is the Chairman of the Board. Further,the director currently presiding at meetings of the independentdirectors is the Vice-Chairman of the Board.***Certifications***     We have filed the required certifications of our chief executiveofficer and our chief financial officer under Section 302of the Sarbanes-Oxley Act of 2002 as exhibits 12.1 and 12.2to this annual report, and we expect to file with the NYSE thechief executive officer certification without exceptions within30 days following our annual general meeting, as requiredby Section 303A.12(a) of the NYSE Listed Company Manual.
63

Table of Contents
**Executive Officers**     The table below provides information about our executiveofficers as of March 31, 2006:               **Executive**      **Officer** **Share****Name (Age)** **Position** **Since** **Ownership**           Svein Rennemo(58)     President and Chief Executive Officer  2002   11,544     Gottfred Langseth(39)     Senior Vice President and Chief Financial Officer  2004   1,158     Rune Eng(44)     President — Marine Geophysical  2004   4,308     Eric Wersich(42)     President — Onshore  2003   1,385     Espen Klitzing(42)     President — Production  2005   1,064      *Mr. Rennemo*joined PGS in November 2002 as presidentand chief executive officer. Prior to joining PGS, he was apartner in ECON Management. From 1997 to March 2001,Mr. Rennemo was chief executive officer of Borealis, one ofthe world’s largest producers of polyolefin plastics,headquartered in Copenhagen, Denmark, having previously servedas chief financial officer and deputy chief executive officersince 1994. From 1982 to 1994, he filled various seniormanagement positions within Statoil, among them group chieffinancial officer and president of Statoil Petrochemicals. From1972 to 198.2, he served as a policy analyst and advisor withthe Central Bank and the Ministry of Finance in the kingdom ofNorway and the OECD Secretariat in Paris. Mr. Rennemoearned a master’s degree in economics at the University ofOslo in 1971. He is a non-executive chairman of the Board ofStatnett SF ( Norway ).     *Mr. Langseth*joined PGS in November 2003 and wasnamed senior vice president and chief financial officer as ofJanuary 1, 2004. He was chief financial officer at theinformation technology company Ementor ASA from 2000 to 2003.Mr. Langseth was senior vice president of finance andcontrol at the offshore construction company Aker Maritime ASAfrom 1997 to 2000. He served with Arthur Andersen Norway from1991 to 1997, qualifying as a Norwegian state authorized publicaccountant in 1993. Mr. Langseth has a master’s degreein business administration from the Norwegian School ofEconomics and Business Administration.     *Mr. Eng*was appointed president of MarineGeophysical in August 2004. Since joining PGS in 1997, he hasheld the position of area manager Scandinavia and from 2000 hasserved as president for the EAME region (Europe, Africa andMiddle East). Prior to joining PGS, Mr. Eng held differentpositions inFugro-Geoteam,including a board position in Sevoteam, a Russian-Norwegianjoint operating company. Mr. Eng has a bachelor’sdegree in applied geophysics from the University of Oslo and amaster of science degree from Chalmers University of Technology(Sweden).     *Mr. Wersich*joined Onshore in January 2000 as vicepresident of western hemisphere and was appointed president ofOnshore in June 2003. Mr. Wersich worked with WesternGeophysical from 1984 to 2000, employed in various operationaland management positions in North America, Latin America, Europeand the Middle East. He is a graduate of the Colorado School ofMines, where he earned a bachelor of engineering degree ingeophysics.     *Mr. Klitzing*joined PGS in May 2005 as senior vicepresident of business development and support. From November2005, Mr. Klitzing has served as president for PGSProduction. From January to April 2005, Mr. Klitzing was aspecial advisor to the private investment company Kistefos. From1999 to 2004, he was CEO of Storebrand Livsforsikring (LifeInsurance), a company with a premium income of NOK9.7 billion and 675 employees. Prior to joining Storebrand,Mr. Klitzing held positions with the consulting firmMcKinsey & Company Inc. Mr. Klitzing also hasserved on numerous boards of directors. Mr. Klitzing has adegree in business administration from the Norwegian School ofEconomics and Business Administration.
64

Table of Contents
**Share Ownership of Directors and Executive Officers**     As of December 31, 2005, the total number of our shares andADSs beneficially held by directors (seven persons) andexecutive officers (five persons) as a group was 3,052,857representing approximately 5.1% of our outstanding shares.Mr. Ulltveit-Moe, chairman of our Board of Directors, isthe founder, chief executive officer and president of UmoeGroup, the parent company of Umoe Industri AS, which as ofDecember 31, 2005 owned 3,037,332 shares, or 5.1% ofour outstanding shares.     On consummation of our reorganization plan, all outstandingoptions for shares were cancelled without compensation to theholders, and as of December 31, 2005 we do not have a shareoption program in place. Our Board of Directors is authorizeduntil June 2007 to issue 6,000,000 shares with a par valueof NOK 10 per share.**Compensation of Directors**     For the year ended December 31, 2005, the aggregate amountwe paid for compensation to our directors as a group forservices in all capacities during 2005 was $548,705. This amountincludes compensation paid to all persons who served asdirectors during any period of 2005. None of our directors hasany contract with us providing benefits upon termination ofservice.**Compensation of Executive Officers**     During the year ended December 31, 2005, we paidcompensation to our president and chief executive officer andother executive officers as follows:               **Year Ended**    **December 31, 2005**         **Fixed Salary**      **and Other**  **Name:** **Position:** **Compensation** **Bonus(a)**           **(In dollars)**    Svein Rennemo     President and Chief Executive Officer $607,454  $177,440     Gottfred Langseth     Senior Vice President and Chief Financial Officer  355,313   82,129     Rune Eng     President — Marine Geophysical  413,333   74,876     Eric Wersich     President — Onshore  262,350   85,259     Espen Klitzing     President — Production, from November 2005  54,597   —     Sverre Skogen     President — Production, through October 2005  189,731   72,751  (a)     2004 bonus paid during 2005, including share purchase bonus.     Included in Svein Rennemo’s fixed salary and othercompensation is an annual pension benefit compensation of$38,998 (equivalent to NOK 250,000). Bonus includes $126,743(equivalent to NOK 812,500) in cash bonus and $50,697(equivalent to NOK 325,000) of share purchase bonus. We alsopaid $57,565 in minimum requirement to a defined benefit plan(for the years 2003, 2004 and 2005). Please read note 22 ofthe notes to our consolidated financial statements inItem 18 of this annual report for additional informationrelating to our defined benefit plan. Starting in 2006,Mr. Rennemo’s fixed annual pension benefitcompensation, included in fixed salary, was reduced toapproximately $30,000 (equivalent to NOK 200,000).     Under our 2005 bonus incentive plan, our President and chiefexecutive officer is entitled to a cash bonus of up to 50% ofannual base salary and a share purchase bonus of up to 30% ofannual base salary. On the basis of achievement of certain groupand financial performance indicators, the Board of Directorsdetermined that our chief executive officer was entitled to acash bonus of $240,246 (equivalent to NOK 1,625,000) and a
65

Table of Contents
share purchase bonus of $144,147 (equivalent to NOK 975,000) for2005. The estimated bonus was accrued as of December 31,2005. The net share purchase bonus amount, after withholdingtaxes, must be used to buy our shares at prevailing marketprices and held for a minimum of three years. Our chiefexecutive officer held 11,544 shares of our company as ofMarch 31, 2006. For additional information regardingMr. Rennemo’s employment arrangements, please read“Additional Information — MaterialContracts — Employment Contract with CEO and CEO BonusScheme” in Item 10 of this annual report.     The aggregate benefits paid to the various defined benefit plansfor executive officers, excluding the chief executive officer,as a group for 2005 was $25,373. As of March 31, 2006,executive officers, excluding the chief executive officer, owneda total of 7,915 shares. None of the executive officersheld any share options in PGS.     For 2005 the Board of Directors established a performance bonusincentive plan for the executive officers similar to that forthe chief executive officer. Under the plan, executive officerslisted above who were employed by us during 2005 and remainemployed as of December 2005 are entitled to a cash bonus of upto 40% of annual base salary and a share purchase bonus of up to20% of annual base salary. Within these limits, bonuses werefinally determined on the basis of achievement of financial andnon-financial performance targets. Any amounts received as ashare purchase bonus, on a net basis (after withholding tax),must be used to buy shares of our company at prevailing marketprices and held for a minimum of three years. The Boarddetermined that the bonus under the scheme for these executivesfor 2005 would be $566,719 in the aggregate, as presented in thetable below, which was accrued at December 31, 2005.           **Accrued 2005 Bonus**    **at December 31,****Name:** **Position:** **2005 (a)**         **(In dollars)**    Gottfred Langseth     Senior Vice President and Chief Financial Officer $186,283     Rune Eng     President — Marine Geophysical  212,895     Eric Wersich     President — Onshore  74,400     Espen Klitzing     President — Production, from November 2005  93,141  (a)     Bonus earned and accrued in 2005, including share purchase bonus.     For the year ended December 31, 2005, we also had a cashbonus and share purchase bonus plan for another group ofapproximately 120 key employees that is similar to the plandescribed above for our executive officers, except that thebonus amounts and percentages for each employee are generallysmaller. We have established bonus plans for 2006 with the sameprinciples as the 2005 bonus plans, covering our executiveofficers and additionally approximately 160 key employees. Wecurrently are not authorized to issue any stock options or otherstock-based awards under any stock option plan or similar planor arrangement for involving employees in the capital of ourcompany.**Employees**     The following table presents information about the number of ouremployees as of the end of each of the last three years:                **At December 31,**     **2005** **2004** **2003**           Marine Geophysical  1,192   1,115   1,143     Onshore(a)  3,237   1,011   1,479     Production  512   501   515     Pertra (sold March 2005)  —   16   5     Global services/ Reservoir/ Corporate  189   256   235                Total  5,130   2,899   3,377           
66

Table of Contents
 (a)     Onshore includes crew hired for specific time periods (generally    the length of the respective project) totaling 3,064; 891 and    1,384 crew members as of December 31, 2005, 2004 and 2003,    respectively. The increase in the number of our Onshore    employees in 2005, as compared with 2004, was primarily    attributable to our hiring of local workers to staff seismic    crews in connection with a single onshore project in Bangladesh.     We have not experienced any material work stoppages related tounion activities during 2005 and consider our relations with ouremployees to be good.**ITEM 7.*****Major Shareholders and Related Party Transactions***     As of March 31, 2006, Umoe Industri AS and Agra AScollectively beneficially own 3,087,332 shares, or 5.2% ofour outstanding shares. Mr. Jens Ulltveit-Moe, founder,chief executive officer and president of Umoe Group, the parentcompany of Umoe Industri AS and Agra AS, serves as chairman ofour Board of Directors. In December 2004,Mr. Ulltveit-Moereduced his percentage of ownership from 9.6% to 5.1%. Pleaseread Item 6 of this annual report for additionalinformation regarding Mr. Ulltveit-Moe.     Based on a Schedule 13G filed with Securities and ExchangeCommission on February 14, 2006, FMR Corp. beneficiallyowns and has sole dispositive power over 5,956,015 shares,or 9.9% of our outstanding shares, and has sole voting powerwith respect to 3,847,908 shares. Members of the family ofMr. Edward C. Johnson, III, chairman of FMR Corp., ownapproximately 49% of the outstanding voting stock of FMR Corp.,and may be deemed to be part of a controlling group with respectto FMR Corp. Fidelity Management & Research Company(“Fidelity”), a wholly owned subsidiary of FMR Corp.,beneficially owns 2,131,957 shares, or 3.6% of ouroutstanding shares. Fidelity acts as an investment advisor tovarious registered investment companies (the “FidelityFunds”). Each of Mr. Johnson and FMR Corp., throughthe control of Fidelity, has sole power to dispose of2,131,957 shares owned by the Fidelity Funds. Each of theFidelity Funds’ boards of trustees has voting power overthe shares held by each fund. Fidelity International Limited(“FIL”), a company of which Mr. Johnson is thechairman, beneficially owns 3,824,058 shares, or 6.4% ofour outstanding shares. FMR Corp. disclaims beneficial ownershipof shares owned by FIL.     Our shareholders that are the beneficial owners of 5% or more ofour ordinary shares do not have different voting rights than ourother shareholders.     As of March 10, 2006, there were 32 record holders of ADSsrepresenting 7,897,983 shares, of which 26 had registeredaddresses in the United States. These 26 United States recordholders held ADSs representing 7,897,820 shares, whichrepresented approximately 13% of the total number of our sharesoutstanding as of that date.     Based upon information available from Verdipapirsentralen, theNorwegian centralized registry of securities, as ofDecember 31, 2005, there were 60,000,000 ordinary sharesoutstanding (including shares represented by ADSs) held by 2,877record holders, of which 114 had registered addresses in theUnited States and 2,406 had registered addresses in Norway. TheUnited States holdings represented 17,751,361 shares, orapproximately 30% of the total number of our shares outstandingas of that date. For this purpose, Citibank, N.A., in itscapacity as the depositary for our ADSs, represents one recordholder of shares. The above numbers may not be representative ofthe actual number of United States beneficial holders or ofshares beneficially held by U.S. persons. The Norwegianholdings represented 12,034,068 shares, or approximately20% of the total number of our shares outstanding as of thatdate.     Please read note 25 of the notes to our consolidatedfinancial statements included in Item 18 of this annualreport for information regarding our related-party transactions.
67

Table of Contents
**ITEM 8.*****Financial Information*****Financial Statements**     Please read Item 18 of this annual report.**Legal Proceedings**     From time to time, we are involved in or threatened with variouslegal proceedings arising in the ordinary course of business.See “Key Information — Risk Factors —Other Risk Factors — We are a multinationalorganization faced with increasingly complex tax issues in manyjurisdictions, and we could be obligated to pay additional taxesin various jurisdictions” in Item 3 of this annualreport. We have identified issues in several jurisdictions thatcould eventually make us liable to pay material amounts in taxesrelating to prior years. Additional issues that we are notcurrently aware of may be identified in the future. We do notbelieve that we are engaged in, or have recently been engagedin, any additional legal or arbitration proceedings that couldhave, or have had, a significant effect on our financialposition or results of operations. We are not engaged in anymaterial proceeding that involves any director, member of seniormanagement or affiliate as an adverse party to us.**Dividend Restrictions**     Our ability to meet parent company-level payment obligationsdepends upon dividends, distributions, advances and otherinter-company transfers from our subsidiaries.     Under Norwegian law, dividends in cash or in-kind as adistribution of our profit and the profits of our Norwegiansubsidiaries are only payable annually, and any proposal by theBoard of Directors to pay a dividend must be recommended by thedirectors and approved by the shareholders at a general meeting.The shareholders may vote to reduce, but not to increase, thedividends proposed. Dividends in cash or in-kind are payableonly out of the following items, as computed for PetroleumGeo-Services ASA(parent company) based on its unconsolidated financialstatements in accordance with Norwegian GAAP: •     the annual profit according to the income statement for the last    financial year;  •     other unrestricted equity, after deduction of:  •     accumulated losses;  •     the book value of research and development, goodwill and net    deferred tax assets recorded on the balance sheet;  •     the aggregate nominal value of treasury shares held by or    pledged to us;  •     the value of such credit or security in favor of our    shareholders, directors or management that can be granted only    out of our unrestricted equity; and  •     any part of the annual profit that, according to law or our    articles of association and the articles of each of our    Norwegian subsidiaries, must be allocated to restricted funds.     Neither we nor our Norwegian subsidiaries can declare dividendsif the equity, according to our unconsolidated Norwegian GAAPbalance sheets, amounts to less than 10% of the balance sheet,or dividends in excess of an amount that is compatible with goodand careful business practice with due regard to any losses thatmay have occurred after the last balance sheet date or that maybe expected to occur. The ability of our foreign subsidiaries totransfer funds to the parent company may be restricted byexchange, statutory or other limitations. In addition, our$1 billion credit facility restricts our ability to paydividends or make similar distributions.     At present, we do not currently expect to pay ordinary dividendsto shareholders. In general, any future dividend will be subjectto determination based on our results of operations andfinancial condition, our future business prospects, anyapplicable legal or contractual restrictions and other factorsthat the Board of Directors considers relevant.
68

Table of Contents
     As described above under “Information on theCompany — Proposed Separation of the Geophysical andProduction Businesses” in Item 4 of this annualreport, the Board of Directors has proposed to our shareholdersthat we separate our geophysical and production businesses intotwo independently listed companies. This separation would beaccomplished through a demerger under Norwegian law of ourproduction business. If the demerger is consummated as planned,it will significantly change the nature of our business and ourcapital structure. The geophysical industry remains cyclical. Weare therefore targeting strong financial flexibility goingforward in a business climate where capturing attractive growthopportunities will be key to shareholder value creation. Thisoverall direction will also guide the Board in formulating andrecommending an appropriate dividend policy for 2006 and lateryears.**Significant Changes**     Except as disclosed in this annual report, no significantchanges have occurred since the date of our 2005 annualfinancial statements.**ITEM 9.*****The Offer and Listing*****Listing Details**     Our ordinary shares are listed on the Oslo Stock Exchange(“OSE”) and trade on that exchange under the symbol“PGS.” These shares are not publicly traded outsideNorway.     We also have American Depositary Shares (“ADSs”) thatare traded on the New York Stock Exchange (“NYSE”)under the symbol “PGS”. Each ADS represents one share.Citibank, N.A. serves as the depositary for the ADSs. PGS listedthe ADSs on the NYSE in April 1997. On February 26, 2003,the NYSE informed us that our ADSs were suspended from the NYSEand that it would commence proceedings with theU.S. Securities and Exchange Commission to delist thesecurities. Our ADSs were then tradedover-the-counter(“OTC”) and were quoted on the Pink Sheets under theticker symbol “PGOGY.”     On November 6, 2003, subsequent to our emergence fromChapter 11, our new ordinary shares began trading on theOslo Stock Exchange and our new ADSs began trading on the OTCPink Sheets under the symbol “PGEOY.”     On December 17, 2004, our ADSs were relisted on the NYSEand began trading under the symbol “PGS.”**American Depositary Shares**     We have presented in the table below, for the periods indicated,the reported high and low closing prices for our ADSs on the NewYork Stock Exchange and the Pink Sheets, as applicable. Uponemergence from Chapter 11 proceedings and consummation of ourfinancial restructuring in November 2003, thepre-restructuringshareholders received one post-restructuring share per 129 oldshares, in addition to the right to subscribe for new shares ina rights offering. The new shares began trading on the PinkSheets on November 6, 2003. The old shares were cancelled.In June 2005 we split our shares three for one. The share pricesin the table below have been adjusted for this three-for-onesplit.           **Price per ADS**   **Calendar Period** **High** **Low**         2001 $4.88  $1.67     2002  2.63   0.12     2003 (through February 26)  0.16   0.10     2003 (February 26 — November 5)  0.50   0.03     2003 (from November 6)  14.33   10.93     2004 (through December 16)  20.75   11.17     2004 (from December 17)  20.69   19.33     2005  31.82   18.91 
69

Table of Contents
           **Price per ADS**   **Calendar Period** **High** **Low**         First Quarter 2004 $17.07  $12.68     Second Quarter 2004  16.00   11.17     Third Quarter 2004  16.17   12.25     Fourth Quarter 2004 (through December 16)  20.75   12.50     Fourth Quarter 2004 (from December 17)  20.69   19.33     First Quarter 2005  24.92   19.83     Second Quarter 2005  25.25   18.91     Third Quarter 2005  31.82   24.00     Fourth Quarter 2005  31.60   24.40     First Quarter 2006  48.99   32.28            **Price per ADS**   **Calendar Period** **High** **Low**         October 2005 $31.60  $24.50     November 2005  28.30   24.40     December 2005  31.05   28.57     January 2006  36.30   32.28     February 2006  40.53   33.94     March 2006  48.99   40.45 **Shares**     We have presented in the table below, for the periods indicated,the reported high and low closing prices for our shares on theOslo Stock Exchange. On November 6, 2003, upon emergencefrom Chapter 11 proceedings and consummation of ourfinancial restructuring, the pre-restructuring shareholdersreceived one new share per 129 old shares, in addition to theright to subscribe for new shares in a rights offering. In June2005 we split our shares three for one. The share prices in thetable below have been adjusted for this three-for-one split.           **Price per Share**   **Calendar Period** **High** **Low**         2001  NOK 41.5   NOK 14.7     2002  23.3   0.9     2003 (through November 5)  3.6   0.4     2003 (from November 6)  105.0   71.0     2004  128.3   81.7     2005  211.0   120.7 
70

Table of Contents
           **Price per Share**   **Calendar Period** **High** **Low**         First Quarter 2004  NOK 121.7   NOK 87.3     Second Quarter 2004  112.3   81.7     Third Quarter 2004  111.0   82.8     Fourth Quarter 2004  128.3   96.3     First Quarter 2005  161.7   124.3     Second Quarter 2005  164.0   120.7     Third Quarter 2005  208.5   156.5     Fourth Quarter 2005  211.0   157.0     First Quarter 2006  326.5   214.5            **Price per Share**   **Calendar Period** **High** **Low**         October 2005  NOK 211.0   NOK 157.0     November 2005  191.0   160.5     December 2005  210.0   195.0     January 2006  244.5   214.5     February 2006  275.5   230.0     March 2006  326.5   274.5 **ITEM 10.*****Additional Information*****Description of Share Capital**     We have summarized below material information about our sharecapital, our articles of association and provisions of Norwegianlaw that apply to our share capital. This summary is notcomplete. For more information about our share capital, weencourage you to read our articles of association, which we havefiled as an exhibit to this annual report.***Organization, Register and Purpose***     We are a public limited liability company organized under thelaws of the Kingdom of Norway. Our registration number with theNorwegian Company Registry is 916235291. As set forth inSection 2 of our articles of association, our business isto provide services to and participate and invest in energyrelated businesses.***Voting Rights***     As a general rule, our shareholders can take action underNorwegian law or our articles of association by a simplemajority of votes cast at a general meeting of shareholders.Each ordinary share carries one vote. Amendments to our articlesof association, however, including any amendment increasing ourshare capital or altering the rights and preferences of anyshare or class of shares, require the approval of at leasttwo-thirds of the votes cast and at least two-thirds of theshare capital represented at a shareholders’ meeting,whether or not holders of the share capital are entitled tovote. In some cases, a stricter voting requirement may apply.     To vote at an annual or extraordinary general meeting, ashareholder must be registered as a holder of title to theshares to be voted in our share register maintained atVerdipapirsentralen (“VPS”), the Norwegian centralizedregistry of securities, not later than at the date of thegeneral meeting. Shareholders who intend to participate in ageneral meeting in person or by proxy must notify us by the datestated in the notice convening the meeting, which date must beat least two business days before the date of the meeting.
71

Table of Contents
     Under our articles of association, the beneficial owner ofshares registered in VPS through a custodian approved by theNorwegian authorities may vote the shares covered by thecustodial arrangement if: •     the beneficial owner provides us, no later than two business    days prior to the meeting, with its name, address and a    confirmation from the custodian that the holder is the    beneficial owner of the shares held in custody; and  •     our Board of Directors does not disapprove the beneficial    ownership after receipt of notification as described below under    “— VPS and Transfer of Shares.”     As an alternative to the voting procedure for beneficial ownersdescribed above, under Norwegian law, owners of ADSsrepresenting shares can vote by surrendering their AmericanDepositary Receipts, or ADRs, evidencing ADSs to the custodianand having title to the related shares registered in our shareregister maintained at the VPS prior to the meeting.     Our annual general meeting of shareholders is held each yearbefore the end of June. Norwegian law requires that writtennotice of general meetings be sent to shareholders whoseaddresses are known at least two weeks prior to the date of themeeting. Under our articles of association, we may call generalmeetings on four weeks’ written notice. A shareholder mayvote by proxy. Although Norwegian law does not require us tosend proxy forms to our shareholders for general meetings, wenormally include a proxy form with the meeting notice. Anyshareholder may demand that a specific issue be placed as anitem on the agenda for any general meeting provided that we arenotified in time for such item to be included in the meetingnotice.     Extraordinary general meetings of shareholders may be held: •     whenever our Board of Directors considers it necessary;  •     at the request of our auditor; or  •     at the request of shareholders representing at least 5% of our    share capital.     Extraordinary general meetings of shareholders may be calledwith two weeks written notice when called at the written requestof our auditor or at the request of shareholders representing atleast 5% of our share capital. The request must name the mattersto be considered. The extraordinary general meeting must beconvened within one month of the date of the request. Other thanapproval of the annual accounts and declaration of dividends,any matter that may be raised at an annual general meeting mayalso be raised at an extraordinary general meeting.     Norwegian law prohibits the general meeting or the Board ofDirectors of any other person representing us from taking anyaction that may give a shareholder an unreasonable benefit atthe expense of other shareholders or us.***Restrictions on Ownership of Shares***     At present, there is no limitation on ownership of shares bypersons who are not Norwegian.***Share Register***     Under Norwegian law, shares are registered in the name of theowner of the shares. As a general rule, there are noarrangements for nominee registration. However, shares may beregistered in the VPS, described below under“— VPS and Transfer of Shares,” by a fundmanager (bank or other nominee) approved by the NorwegianMinistry of Finance, as the nominee of foreign shareholders. Anapproved and registered nominee has a duty to provideinformation on demand about beneficial shareholders to thecompany and to the Norwegian authorities. In the case ofregistration by nominees, registration with the VPS must showthat the registered owner is a nominee. Registration mustinclude the nominee’s name, address and number of sharesthat are the subject of the nomination agreement. A registerednominee has the right to receive dividends and otherdistributions but cannot vote at general meetings on behalf ofthe beneficial owners. Beneficial owners must register with theVPS or provide other proof of their acquisition of the shares inorder to vote at general meetings.
72

Table of Contents
***VPS and Transfer of Shares***     Norway has a paperless, centralized registry of shares and othersecurities, VPS. We and all other Norwegian public companies areobligated to register our shares in VPS. Share certificates arenot used. VPS is a computerized bookkeeping system operated byan independent body in which the ownership of and alltransactions relating to Norwegian listed shares must berecorded. Our share register is operated through VPS under VPSnumber 000-4225004.     All transactions relating to securities registered with VPS aremade through computerized book entries. VPS confirms each entryby sending a transcript to the registered shareholderirrespective of any beneficial ownership. To effect an entry,the individual shareholder must establish a share account with aNorwegian account agent. Norwegian banks, the Bank of Norway,authorized securities brokers in Norway and Norwegian branchesof credit institutions established within the European EconomicArea are allowed to act as agents. If the shareholder does notestablish an account, the issuing company will appoint an agenton the shareholder’s behalf.     A VPS entry represents prima facie evidence in determining thelegal rights of a registered holder of a security against theissuing company or a third party claiming an interest in thesecurity.     VPS is strictly liable for any loss resulting from an error inconnection with registering, altering or canceling a right,except in the event of contributory negligence, in which eventcompensation owed by the VPS may be reduced or withdrawn.     Under Norwegian law, a transferor must register immediately withVPS any acquisition or other transfer of shares. A person towhom shares have been transferred or assigned may exercise therights of a shareholder for those shares only if: •     the transfer or assignment has been registered or that person    has reported and shown evidence to us of the share    acquisition; and  •     the acquisition is not prevented by law, our articles of    association or otherwise.     Our articles of association provide that our shares are freelytransferable, except that an acquisition by assignment issubject to approval by our board of directors,****whichcannot be withheld without reasonable grounds. This provisioncould operate to prevent or impede a change in control of ourcompany.***ADSs and Transfer and Voting***     Our shareholders may choose to hold our shares as ADSs, in whichcase the shares are represented by ADRs. ADSs may betransferred, at the option of the holder, by transferring therelated ADRs, or by requesting that the underlying shares beissued to the holder, who then transfers them to the transferee.Holders of ADSs may vote the underlying shares by: •     requesting that the shares be certificated by having them    transferred to a VPS account in the name of the holder;  •     providing name and address information, and a confirmation from    Citibank N.A., as depositary for the ADSs, to the effect that    the holder is the beneficial owner of the underlying    shares; or  •     authorizing Citibank N.A. to vote the ADSs on the holder’s    behalf.***Disclosure Obligations***     Under Norwegian law, a person, entity or group acting in concertmust notify the Oslo Stock Exchange immediately of anacquisition or disposition of shares or rights to shares and ofits aggregate holdings of shares or rights to shares followingthe acquisition or disposition,****if the acquisition ordisposition results in the holder’s aggregate beneficialownership of shares or rights to shares reaching, exceeding orfalling below thresholds of1/20,1/10,1/5,1/3,1/2,2/3or9/10 of the total number of shares outstanding or of theoutstanding voting rights. A corresponding disclosure obligationapplies to holders of ADRs.
73

Table of Contents
***Additional Issuances and Preemptive Rights***     To issue additional shares, including bonus issues (sharedividends), we must amend our articles of association. Thisamendment requires the same shareholder vote as other amendmentsto our articles of association, which is at least two-thirds ofthe votes cast and at least two-thirds of the share capitalrepresented at the meeting. Our shareholders also must approveby the same vote the issuance of loans convertible into sharesor warrants to purchase shares. At a general meeting, theshareholders may by the same majority authorize our Board ofDirectors to issue: •     an aggregate number of shares not exceeding 50% of the number of    shares outstanding at the time of the general meeting; and  •     loans convertible into an aggregate number of shares not    exceeding 50% of the number of shares outstanding at the time of    the general meeting.     The duration of these authorizations cannot exceed two years.     Under Norwegian law, shareholders have preemptive rights tosubscribe for and be allotted new shares that we issue.Shareholders may waive those preemptive rights in a generalmeeting by the same vote required to approve amendments to ourarticles of association. A waiver of shareholders’preemptive rights for bonus issues (share dividends) must beapproved by the holders of all shares outstanding.     If we issue shares upon the exercise of preemptive rights toholders who are citizens or residents of the United States, wemay be required to file a registration statement in the UnitedStates under U.S. securities laws. If we decide not to filea registration statement, those U.S. holders would not beable to exercise their preemptive rights and would be requiredto sell them to Norwegian persons or othernon-U.S. holdersto realize the value of the rights.     Under Norwegian law and with shareholder approval, we maydistribute bonus issues (share dividends) of our shares fromamounts: •     that we could otherwise distribute as dividends; or  •     that we may create by transferring funds from our share premium    reserve discussed below under “— Dividends and    Legal Reserves” to share capital.     We can implement bonus issues (share dividends) either byissuing shares or by increasing the par value of the sharesoutstanding.     At our Annual General Meeting in June 2005, our Board ofDirectors was authorized to increase our share capital by up to6,000,000 shares through one or more subscriptions. Theauthorization is valid until June 2007. The authorization wasunused as of December 31, 2005.***Dividends and Legal Reserves***     Please read “Financial Information — DividendRestrictions” in Item 8 of this annual report forinformation regarding our ability to pay dividends or distributeprofits to our shareholders, and whether we intend to paydividends. We hereby incorporate information called for by thisItem 10 by reference to the information under that caption.     Under Norwegian law, we are required to maintain reserves thatare adequate in light of our activities and related risks. Wemust allocate to the share premium (restricted) reserve anypremium paid to us for the subscription of new shares.***Examination of PGS and its Accounts***     Under Norwegian law, any shareholder may request that Norwegiancourts order an examination of our company and accounts if suchrequest is approved by 10% or more of the aggregate sharecapital represented at any general meeting.
74

Table of Contents
***Rights upon Winding-Up***     A Norwegian company may be wound up by a resolution of thecompany in a general meeting passed by at least two-thirds ofthe aggregate votes cast by its voting shares and by at leasttwo-thirds of the aggregate share capital represented at themeeting irrespective of class. The shares rank pari passu in theevent of a return of capital by the company on awinding-up or otherwise.***Interested Director Transactions***     Under Norwegian law, a director may not participate in adiscussion or decision of any matter in which the director orany related person of the director has a significant personal orfinancial special interest. In addition, under Norwegian law, adirector may not participate in a discussion or decisioninvolving any proposed loan or other credit to the director orpledge of security for the director’s debt.***Other Provisions Relating to Directors***     Each of our directors stands for election at our annual generalmeeting, and our directors do not serve staggered terms. Thereis no cumulative voting for directors.     Under Norwegian law, any compensation payable to a director mustbe determined by the shareholders in a general meeting. There isno mandatory retirement provision under Norwegian law or ourarticles of association, nor is there a requirement that ourdirectors own our shares or ADSs.***Mandatory Bid Requirement***     Norwegian statutory law requires any person, entity, familygroup or other group acting in concert that acquires shares(including ADSs) representing more than 40% of the voting rightsof a Norwegian company listed on the Oslo Stock Exchange tonotify the Oslo Stock Exchange immediately and to make a generaloffer to acquire all the outstanding share capital of thatcompany. Such offer must be made no later than four weeks afterthe obligation is triggered and in the form of an offer documentto all shareholders. The offer may not be conditional and issubject to approval by the Oslo Stock Exchange before submissionto the shareholders. The offer must be in cash or contain a cashalternative at least equivalent to any other considerationoffered. The offering price per share must be the greater of: •     the highest price paid by the offeror for the shares in the    six-month period prior to the date the 40% threshold was    exceeded; or  •     the recorded market price at that date.     If the acquirer acquires, or agrees to acquire, additionalshares at a higher price after exceeding the 40% threshold butprior to the expiration of the four-week bid period, theacquirer must restate its bid at that higher price. If ashareholder who is required to make a mandatory bid fails to doso, the shareholder must within four weeks dispose of sufficientshares so that the obligation ceases to apply. Otherwise, theOslo Stock Exchange may cause the shares exceeding the 40% limitto be sold by public auction.     During the time the mandatory bid requirement is in force, ashareholder failing to make the required offer may not vote orexercise any rights of share ownership other than the right toreceive dividends and preferential rights relating to a sharecapital increase, unless a majority of the remainingshareholders approve. In addition, the Oslo Stock Exchange mayimpose a daily fine upon a shareholder who fails to make therequired offer.     Citibank, N.A., the depositary for our ADSs, has qualified andbeen recognized as a custodian of the shares in Norway. As aresult, it is exempt from the mandatory bid requirement.***Sale of All or Substantial Part of Our Property or    Assets***     There is no general requirement under Norwegian law that thesale, lease or exchange of all or substantially all of theproperty or assets of a Norwegian company requires shareholderapproval in addition to
75

Table of Contents
the approval of the Board of Directors, unless such atransaction would imply that the business and purpose of thecompany as described in its articles of association would beamended, in which event the approval of at least two-thirds ofthe votes cast and at least two-thirds of the share capitalrepresented at the meeting is required.***Compulsory Acquisition (Squeeze Out/ Sell Out    Right)***     Under Norwegian law, if a shareholder, directly or indirectly,acquires shares of a Norwegian company representing more than90% of the total number of shares outstanding or of theoutstanding voting rights, then such majority shareholder hasthe right (and each remaining minority shareholder of thecompany has the right to require such majority shareholder) toeffect a compulsory acquisition for cash of any shares notalready owned by such majority shareholder. Under such acompulsory acquisition, the majority shareholder becomes theowner of the acquired shares with immediate effect. Uponeffecting the compulsory acquisition, the majority shareholderwould be required to offer the minority shareholders a specificprice per share, the determination of which price would be atthe discretion of the majority shareholder. If any minorityshareholder does not accept the offered price, such minorityshareholder may, within a specified deadline of not less thantwo months, request that the price be set by the Norwegiancourts. Generally, the cost of any such court procedure would beborne by the majority shareholder, and the courts would havefull discretion in respect of the valuation of the shares forthe compulsory acquisition. In the absence of such a request orother objection to the price being offered by the majorityshareholder, the minority shareholders would be deemed to haveaccepted the offered price after the expiration of a two-monthperiod.**Exchange Controls and Other Limitations Affecting Security    Holders**     Under Norwegian foreign currency exchange controls currently ineffect, transfers of capital to and from Norway are not subjectto prior governmental approval except for the physical transferof payments in currency, which is restricted to licensed banks.As a result, a non-Norwegian resident may receive dividend,principal and interest payments on our securities without aNorwegian exchange control consent, but the payments must bemade through a licensed bank.     There are no limitations imposed by Norwegian law or ourarticles of association on the right to hold or vote shares thatapply differently to non-Norwegian owners than to Norwegianowners.**Material Contracts**     We provide below a summary of material contracts that we haveentered into in the last two years, other than contracts enteredinto in the ordinary course of our business. The descriptionsbelow are qualified in their entirety by reference to theagreements being described, which are listed in Item 19 ofthis annual report.***Employment Contract with CEO and CEO Bonus Scheme***     On January 26, 2006, we entered into a new employmentagreement with Svein Rennemo, our Chief Executive Officer. Thenew agreement replaced Mr. Rennemo’s 2002 employmentagreement.     The new employment agreement provides (i) for an annualsalary in 2006 of NOK 3,250,000, which salary is subject toannual review, (ii) for a car allowance of NOK 225,000,(iii) that Mr. Rennemo may participate in (A) ourgroup life, accident and travel insurance and other personnelinsurance that we provide, and (B) our CEO bonusarrangement and (iv) for vacation and holidayallowance/pay. As pension compensation, we are obligated(1) to pay to Mr. Rennemo NOK 200,000 annually ascompensation for lack of an executive pension arrangement,(2) commencing January 1, 2006, to make a contributionfor the benefit of Mr. Rennemo to the general pensioninsurance scheme (as applicable to all Norwegian employees), and(3) make a lump sum payment of NOK 361,058 to the generalpension insurance scheme (as applicable to all Norwegianemployees) to compensate for the lack of premium payments fromthe commencement of Mr. Rennemo’s employment in 2002through 2005.
76

Table of Contents
     Mr. Rennemo’s employment will terminate atage 60, unless we otherwise agree in writing withMr. Rennemo. In addition, both we and Mr. Rennemo canterminate the employment agreement with 12 months noticeor, if the period of time remaining prior toMr. Rennemo’s60th birthdayis less, notice of such lesser period of time. The employmentagreement may also be terminated by us for breach of contract byMr. Rennemo.     In 2004, we also instituted our 2004 CEO Bonus Scheme, pursuantto which our CEO is eligible for a cash bonus of up to 50% ofhis base salary and a share bonus of up to 30% of his basesalary. The maximum amount of any cash or share bonus is basedon the achievement by PGS of certain specified financial goals.The actual amount of any cash or share bonus is based on theachievement by PGS and the CEO of certain specified goals. Thenet amount, after withholding taxes, of any share bonus must beinvested in our shares. Shares purchased with this bonus must beheld for at least three years, unless our Board of Directorsconsents to an earlier sale.***December 2005 Credit Facility***     On December 19, 2005, we and certain of our affiliatesentered into a $1 billion senior secured credit facilitywith the lenders named therein. Please see “Operating andFinancial Review and Prospects — 2005Refinancing” and “— Liquidity and CapitalResources — Sources of Liquidity — CapitalResources” in Item 5 of this annual report for adescription of this credit facility.***Sale of Pertra***     On March 1, 2005, we sold Pertra to Talisman for a salesprice of approximately $155 million. Please read“Information on the Company — Sale of Our Oil andNatural Gas Subsidiary Pertra” in Item 4 andnote 24 of the consolidated financial statements includedin Item 18 of this annual report for a description of thistransaction.**Taxation*****General***     The following discussion generally summarizes the principalNorwegian and U.S. federal income tax consequences of theownership and disposition of our ADRs, which evidence our ADSs,and our shares to holders of ADRs and shares who are residentsof the United States or otherwise subject to U.S. federalincome taxation on a net income basis for ADRs and shares andwho are not residents of Norway (“U.S. Holders”).The summary applies only to holders who will hold ADRs or sharesas capital assets and does not address certain classes ofholders, such as holders who own, directly or indirectly, atleast 10% of our outstanding shares, which may be subject tospecial rules. Because it is a general summary, prospectivepurchasers of ADRs or shares who would be U.S. Holders areadvised to consult their own tax advisors about theU.S. federal, state and local tax consequences and theNorwegian tax consequences of the ownership and disposition ofADRs and shares that are applicable in their particular taxsituations, including the effects of recent and possible futurechanges in the applicable tax laws.     The summaries of U.S. and Norwegian tax laws provided below arebased on the tax laws of the United States and Norway, theincome tax convention between the United States and Norway (the“Convention”) and interpretations by the relevant taxauthorities that are in effect as of the date of this annualreport and are subject to any changes that may occur after thatdate (possibly with retroactive effect).     For U.S. and Norwegian tax purposes, U.S. Holders of ADRswill be treated as the owners of the shares represented by theADRs. Unless we have otherwise stated below, the Norwegian taxconsequences and the U.S. federal income tax consequencesdiscussed below apply equally to U.S. Holders of ADRs andU.S. Holders of shares.     We believe, and this discussion assumes, that we are not andhave never been a passive foreign investment company as thatterm is defined in the U.S. Internal Revenue Code of 1986,as amended (the “Code”).
77

Table of Contents
***Taxation of Dividends***     Under Norwegian tax law, dividends paid to foreign shareholdersof Norwegian corporations are, unless otherwise provided for inan applicable tax treaty, subject to a withholding tax in Norwayof 25%. Under the Convention, the maximum rate of withholdingtax on dividends paid by a Norwegian corporation to a“resident of the United States,” as defined in theConvention, is 15%. The 15% withholding rate will apply to anydividends paid on our shares held directly by U.S. Holderswho properly demonstrate to us and to the Norwegian taxauthorities that they are entitled to the benefits of theConvention. Dividends paid to Citibank, as depositary, will besubject to withholding at the 25% rate. U.S. Holders ofADRs who believe they are entitled to the benefits of theConvention may apply to the Norwegian tax authorities for arefund of amounts withheld in excess of 15%. The application isto be filed with the Norwegian Central Office —Foreign Tax Affairs. There is some uncertainty, however, as towhether and when such a refund may be obtained.     We intend to file any reports with the Norwegian authorities oragencies necessary to obtain the benefits of the Convention forthose entitled to them. We will exercise our right under thedeposit agreement to reasonably request from Citibank suchinformation from its records that will enable us to file thereports.     If, however, the recipient of a dividend is determined to beengaged in a business activity taxable in Norway and our sharesor ADSs with respect to which the dividend is paid areeffectively connected with that activity, then the amountdistributed to the U.S. Holder will be treated as taxabledomestic dividend income in Norway, subject to the provisions ofthe Convention, where applicable. After the amendments to theNorwegian tax law, the dividend could potentially be exemptedfrom taxation in Norway if the business activity in Norway isowned by a corporate entity in the United States, but the legalsituation is unclear. Such U.S. Holders should seek furthertax advice regarding their tax situation in Norway. Dividendswill be taxable if a U.S. holder who is an individual withbusiness activity in Norway owns shares, and our shares or ADSsare effectively connected with that activity. Dividends receivedby the individual shareholder exceeding a risk-free rate ofreturn are subject to taxation at 28%. The risk-free rate ofreturn is calculated for each individual share on the basis ofthe cost price (including RISK amount up to 1 January 2006)multiplied with an opportunity rate of interest (risk-free rateof interest after tax).     To the extent paid out of our current or accumulated earningsand profits, distributions made on our shares or ADSs, otherthan certain distributions of our capital stock or rights tosubscribe for shares of our capital stock, will be includible inthe income of a U.S. Holder for U.S. federal incometax purposes as ordinary dividend income. In the case of aU.S. Holder of an ADR, such dividend income will berecognized on the date Citibank receives the distribution.Dividends we pay will not be eligible for the dividends-receiveddeduction generally allowed to corporations under the Code. Theamount of a dividend distribution for tax purposes will equalthe U.S. dollar value of the amount of the distribution inNorwegian kroner (including the amount of Norwegian taxeswithheld from the distribution), calculated by reference to theexchange rate in effect on the date of the distribution. Uponthe ultimate conversion by Citibank into U.S. dollars ofthe Norwegian kroner received in a distribution,U.S. Holders of ADRs generally will recognize gain or lossfor U.S. federal income tax purposes equal to thedifference, if any, between such U.S. dollars and theU.S. dollar value of such Norwegian kroner on the date ofthe distribution. Such gain or loss will be treated as ordinaryincome or loss.     For taxable years beginning on or before December 31, 2008,dividend income received by an individual, estate, or trust froma corporation organized in the U.S. or from a“qualified foreign corporation” generally is taxed atthe lower rates imposed on long-term capital gains recognized byindividuals. The maximum rate of tax for such dividends is 15%.     Anon-U.S. corporationis a “qualified foreign corporation” if either(i) its stock with respect to which the dividend is paid isreadily tradable on an established securities market in theU.S. or (ii) the corporation is eligible for thebenefits of a comprehensive tax treaty with the U.S. thatthe Internal Revenue Service (“IRS”) determines issatisfactory for purposes of the provision reducing the rate oftax on dividends, and that includes an exchange of informationprogram. Our ADSs are readily tradable on an establishedsecurities market in the U.S. because they are listed onthe NYSE. Moreover, we are eligible for benefits under theConvention, and the IRS has identified the Convention assatisfactory for purposes of the provision reducing
78

Table of Contents
the rate of tax on dividends and as including an exchange ofinformation program. Accordingly, U.S. Holders that areindividuals, estates, or trusts generally will be eligible forthe lower long-term capital gains rates with respect todividends paid on our shares or ADSs.     A U.S. Holder will not be allowed to benefit from the lowerlong-term capital gains rates unless the U.S. Holder(i) holds our shares or ADSs for more than 60 daysduring the 121-dayperiod beginning on the date that is 60 days before thedate on which the shares or ADSs become ex-dividend(disregarding any period during which the U.S. Holder has adiminished risk of loss with respect to such shares or ADSs),and (ii) is not under an obligation to make relatedpayments with respect to positions in substantially similar orrelated property.     Norwegian taxes imposed on dividend distributions on our sharesor ADSs generally will be eligible for credit against theU.S. Holder’s U.S. federal income taxes. Theamount of the Norwegian taxes eligible for this foreign taxcredit generally will be equal to the amount of such taxeswithheld from the dividend distributions, reduced by the amountof any refunds of such taxes subsequently received.U.S. Holders that are eligible for benefits under theConvention will not be entitled to a foreign tax credit for theamount of any Norwegian taxes withheld in excess of the 15%maximum rate, and with respect to which the holder can obtain arefund from the Norwegian taxing authorities. U.S. Holdersthat are accrual basis taxpayers generally must translateNorwegian taxes into U.S. dollars at a rate equal to theaverage exchange rate for the taxable year in which the taxesaccrue (except that such a U.S. Holder may elect totranslate Norwegian taxes using the exchange rate at the timethe taxes are paid if the U.S. Holder’s functionalcurrency for tax purposes is not the Norwegian kroner). AllU.S. Holders must translate taxable dividend income intoU.S. dollars at the spot rate on the date received. Thisdifference in exchange rates may reduce the U.S. dollarvalue of the credits for Norwegian taxes relative to theU.S. Holder’s U.S. federal income tax liabilityattributable to the dividend.     Under the foreign tax credit limitations of the Code, theforeign tax credit can offset U.S. federal income taxesimposed on foreign-source income but not onU.S.-source income. Inaddition, foreign taxes imposed on income in certain categoriesspecified in the Code may only be used to offset U.S. taxeson income in the same category. Subject to special rules wedescribe below, dividends we pay will generally beforeign-source income within either the “passiveincome” category or the “financial servicesincome” category, depending on the particularU.S. Holder’s circumstances. For taxable yearsbeginning after December 31, 2006, dividends thatpreviously would have been “passive income” willgenerally be “passive category income” and dividendsthat previously would have been “financial servicesincome” will generally be “general categoryincome.”     The Code contains a provision that could, in certaincircumstances, cause a portion of the dividends we pay to betreated as U.S.-sourceincome. Even if that provision applied to dividends we pay to aU.S. Holder, because of the source rules contained in theConvention, no portion of such a dividend would berecharacterized asU.S.-source income ifthe U.S. Holder includes the dividend as a separatecategory of income for purposes of the foreign tax creditlimitation.     If a U.S. Holder that is an individual, estate, or trust istaxed at the lower long-term capital gains rates on dividends wepay, the Code contains a provision that will cause a portion ofany dividend eligible for this lower rate to be treated asU.S.-source income.This provision is intended to limit the amount of the Norwegiantaxes eligible for the foreign tax credit to the amount ofU.S. tax paid by the U.S. Holder at the lowerlong-term capital gains rates. U.S. Holders are advised toconsult their own tax advisors when determining the portion ofany dividend that will be treated asU.S.-source incomeunder this provision.     A U.S. Holder will not be allowed to claim foreign taxcredits (but would instead be allowed deductions) for foreigntaxes withheld on a dividend if the U.S. Holder(i) has not held the shares for at least 16 days inthe 31-day periodbeginning 15 days before the date on which the sharesbecome ex-dividend with respect to such dividend or (ii) isunder an obligation to make related payments with respect topositions in property that is substantially similar or relatedto the shares.
79

Table of Contents
***Taxation of Ordinary Dispositions***     A U.S. Holder normally is not taxed in Norway on gains fromthe sale or other disposal of our shares or ADSs. Such a holdermay be subject to taxation if the shareholding is effectivelyconnected with a business carried out by the shareholder througha permanent establishment in Norway. In addition, a shareholdermay be subject to taxation on gains if the shareholder is anindividual who has been a resident of Norway for income taxpurposes and the disposal takes place within five years afterthe calendar year in which the shareholder ceased to be aresident of Norway. The same rules apply to gains realized uponcomplete liquidation of us or upon redemption of our shares orADSs. Repayment in connection with a reduction of our sharecapital by reducing the nominal value of the shares is, however,subject to withholding tax as a dividend distribution, ifexceeding paid-in capital.     Under Norwegian tax law, gains from the sale or other disposalof our shares or ADSs by a U.S. Holder is taxable in Norwayif the U.S. Holder is engaged in a business activitytaxable in Norway and our shares or ADSs are effectivelyconnected with that activity. After the amendments to theNorwegian tax law, such gains could potentially be exempted fromtaxation when the U.S. Holder with the business activity inNorway is a corporate entity, but the legal situation is farfrom certain. We recommend that such U.S. Holders seekfurther tax advice regarding their tax situation in Norway.Losses are deductible if the gains are taxable. Gains fromdisposal of shares will be taxable as general income at a flatrate of 28% if a U.S. holder who is an individual withbusiness activity in Norway owns the shares, and our shares orADSs are effectively connected with that activity. Losses onshares are deductible in the shareholders ordinary income. Gainor loss for the individual shareholder is calculated per share,as the difference between the consideration received and the taxbasis for the share. The tax basis of each share is based on theshareholder’s purchase price for the share. The individualshareholder is entitled to deduct a deemed allowance whencalculating taxable gain on sale of shares. The allowance foreach share will be equal to the cost price of the sharemultiplied by a determined risk-free interest rate (see sectionon dividend taxation above). The tax liability and deductibilityapply irrespective of how long the shares have been owned andthe number of shares that are sold. If the shares disposed ofhave been acquired at different times, the shares that werefirst acquired will be deemed as first sold. Costs incurred inconnection with the purchase and sale of shares are deductiblein the year of sale, provided that the gain is not exempted fromtaxation.     A U.S. Holder will recognize capital gain or loss forU.S. federal income tax purposes on a sale or otherdisposition of our shares or ADSs (or rights to subscribe forour shares), including a sale or other disposition by Citibankof shares (or rights to subscribe for shares) received asdividends on the ADSs, in the same manner as on the sale orother disposition of any other shares held as capital assets (orrights to acquire such shares). Such capital gain or loss willbe an amount equal to the difference between theU.S. dollar value of the amount realized and theU.S. Holder’s tax basis in the shares. Such capitalgain or loss will be long-term if the shares have been held formore than one year. Long-term capital gains recognized byindividuals, estates, and trusts are eligible for taxation atrates not in excess of 15%. Any such gain or loss will generallybe U.S.-source incomeor loss.     Regardless of the holding period of the shares or ADSs disposed,if an individual U.S. Holder receives a dividend from usqualifying for the long-term capital gains rates and suchdividend constitutes an “extraordinary dividend,” andthe U.S. Holder subsequently recognizes a loss on the saleor exchange of our shares or ADSs, then the loss will belong-term capital loss to the extent of such “extraordinarydividend.” An “extraordinary dividend” for thispurpose is a dividend in an amount (i) greater than orequal to 10% of the taxpayer’s tax basis (or fair marketvalue as of the day before the ex-dividend date) of theunderlying shares or ADSs, aggregating dividends withex-dividend dates within an85-day period, or(ii) in excess of 20% of such tax basis (or fair marketvalue as of the day before the ex-dividend date), aggregatingdividends with ex-dividend dates within a period of365 days.     A U.S. Holder will not be allowed to claim foreign taxcredits (but would instead be allowed deductions) for foreigntaxes imposed on a gross basis on gain with respect to thedisposition of our shares or ADSs unless the U.S. Holder(i) holds such shares or ADSs for more than 15 daysduring the 31-dayperiod beginning on the date that is 15 days before theright to receive payment arises (disregarding any period duringwhich the
80

Table of Contents
U.S. Holder has a diminished risk of loss with respect tosuch shares or ADSs) and (ii) is not under an obligation tomake related payments with respect to positions in substantiallysimilar or related property.     Deposits and withdrawals of our shares in exchange for ADRs willnot result in taxable gain or loss for U.S. or Norwegiantax purposes.***U.S. Backup Withholding***     Certain payments, including certain dividends and proceeds fromsales of stock, may be subject to U.S. “backupwithholding” at the current 28% rate if the recipient ofsuch a payment fails to provide an accurate taxpayeridentification number or certification of U.S. status orfails to report all interest and dividends required to be shownon its U.S. federal income tax returns, or otherwise failsto establish an exemption from withholding. Any amounts sowithheld would be allowed as a credit against therecipient’s U.S. federal income tax liability for theyear. Dividends we pay to a U.S. Holder generally would besubject to these backup-withholding rules.***Gift and Estate Tax***     An individual U.S. Holder will be subject to U.S. giftand estate taxes with respect to our shares in the same mannerand to the same extent as with respect to other types ofpersonal property.***Norwegian Transfer Tax***     There is no Norwegian stock transfer tax or capital tax upon theacquisition or subsequent disposition of our shares or ADSs.***Norwegian Inheritance Tax***     There is no Norwegian inheritance tax or gift tax on our sharesor ADSs if the deceased, at the time of death, or the donor atthe time the gift is made, is neither a resident nor a nationalof Norway. If the deceased, at the time of death, is not aresident of Norway, but is a national of Norway, Norwegianinheritance tax will be levied unless inheritance tax or similartax is levied in the country of residence and the shares are noteffectively connected to a permanent establishment in Norway.Under all circumstances, a transfer of shares or ADSs will besubject to gift tax in Norway if the donor at the time of thegift is a Norwegian national.***Norwegian Property Taxes or Similar Taxes***     U.S. Holders of our shares or ADSs are not subject toNorwegian property tax or similar taxes (e.g., wealth taxes)with respect to those shares or ADSs, unless the shareholding iseffectively connected with a business carried out by theshareholder through a permanent establishment in Norway.**Documents on Display**     Please read “Where You Can Find More Information” forinformation about where you may read and copy documents referredto in this report that we have filed with the SEC.**Subsidiary Information**     Please read “Information on the Company —Organizational Structure” in Item 4 of this annualreport for information regarding our subsidiaries.**ITEM 11.*****Quantitative and Qualitative Disclosures About Market    Risk***     We are exposed to certain market risks, including adversechanges in interest rates and foreign currency exchange rates,as discussed below. We have entered into the financialinstruments described below in order to manage our exposure tothese risks, and not for trading purposes.
81

Table of Contents
**Interest Rate Risk**     We enter into from time to time various financial instruments,such as interest rate swaps, to manage the impact of possiblechanges in interest rates. Our exposure to changes in interestrates results primarily from (a) outstanding indebtednessunder our new $1 billion secured credit facility, whichbears interest at a floating rate, (b) short-termindebtedness outstanding from time to time, (c) our capitalleases and (d) our UK leases. As of December 31, 2005,we have entered into interest rate swaps relating to$425 million of the $850 million term loan and changedour interest rate exposure from floating to fixed for the$425 million notional amount. In addition, as of that datewe had smaller interest rate swaps with the notional amount of$8.6 million, which expired in part in January 2006and the remaining balance of which we settled inFebruary 2006. The following table presents principalamounts and related average interest rates by year of maturityfor our debt obligations as of December 31, 2005:                            **2006** **2007** **2008** **2009** **2010** **Thereafter**               **(Dollar amounts in thousands)**    Debt:                            Fixed rate $11,920  $12,900  $14,040  $15,160  $21,054  $17,480     Average interest rate  8.28%  8.28%  8.28%  8.28%  8.66%  8.28%    Variable rate $9,812  $8,500  $8,500  $8,500  $8,500  $807,500      Interest rate  LIBOR*   LIBOR*   LIBOR*   LIBOR*   LIBOR*   LIBOR*               + applicable margin**            Interest swap notional amount         $150,000      $275,000          — pays fixed interest rate          4.84%      4.88%         — receive floating interest rate          3M LIBOR       3M LIBOR       *     1, 3 or 6 month LIBOR rate**     for applicable margin see Note 16 to our consolidated    financial statements included in Item 18 of this annual    report.     As of December 31, 2005, we had $851.3 million ofinterest-bearing debt bearing interest at floating interestrates based on U.S. dollar LIBOR plus a margin. For everyone-percentage point increase in the LIBOR, our annual interestexpense on such amount of indebtedness will increase by$8.5 million. For every one percentage point increase inthe LIBOR, the annual amount of interest we would receive oninterest rate swaps in place as of December 31, 2005 wouldincrease by $4.2 million. Based on such amount ofindebtedness and interest rate swaps, a one-percentage pointincrease in LIBOR would result in a net increase in our annualinterest costs of approximately $4.3 million.     As of December 31, 2005, we had capital lease obligationsof $33.7 million payable through 2008. Interest associatedwith these capital lease obligations is based onU.S. dollar LIBOR plus a margin. For every one-percentagepoint increase in LIBOR, our interest expense associated withsuch capital lease obligations will increase by approximately$0.2 million for 2006.     As described under “Operating and Financial Review andProspects — Liquidity and CapitalResources — UK Leases” in Item 5 of thisannual report, we have entered into certain capital leases inthe United Kingdom. The leases are legally defeased because wehave made payments to independent third-party banks inconsideration for which these banks have assumed liability tothe lessors equal to basic rentals and termination sumobligations. The defeased rental payments are based on assumedSterling LIBOR rates between 8% and 9% per annum. If actualinterest rates are greater than the assumed interest rates, wereceive rental rebates. If, on the other hand, actual interestrates are less than the assumed interest rates, we are requiredto pay rentals in excess of the defeased rental payments. Forevery one percentage point that LIBOR exceeds these assumedinterest rates, we are entitled to receive approximately£10.4 million ($18.0 million) in rental rebates.On the other hand, for every one percentage point that LIBOR isless than these assumed interest rates, we are required to payan additional approximately £10.3 million($17.9 million) in defeased
82

Table of Contents
rental payments. As of December 31, 2005, our balance sheetreflected a liability of approximately £22 million($38.1 million) for this interest rate exposure. Thisliability was recorded upon our adoption of fresh startreporting and is amortized systematically based on future rentalpayments. During 2005, 2004 and 2003, actual interest rates werebelow the assumed interest rates, and we made additionalrequired rental payments of approximately $7.2 million,$7.2 million and $6.4 million, respectively. Theestimated net present value of future payments related tointerest rate differential on our UK leases as ofDecember 31, 2005 was $54.5 million based on forwardinterest rate curves, which is $16.4 million higher thanthe amount included in accrued liabilities from fresh startreporting. For additional information with respect to our UKleases, please read “Operating and Financial Review andProspects — Liquidity and CapitalResources — UK Leases” in Item 5 andnotes 2 and 20 of the notes to our consolidated financialstatements in Item 18 of this annual report.**Foreign Currency Exchange Rate Risk**     We conduct business in various currencies including theBangladeshi taka, Bolivian boliviano, Brazilian real, Indianrupee, Kazakhstan tenge, Mexican peso, Nigerian naira, Saudiriyal, United Arab Emirates dirham, Venezuelan bolivar, Britishpound and the Norwegian kroner. We are subject to foreigncurrency exchange rate risk on cash flows related to sales,expenses, financing and investing transactions in currenciesother than the U.S. dollar.     Our cash flows from operations are primarily denominated inU.S. dollars, British pounds and Norwegian kroner. Wepredominantly sell our products and services inU.S. dollars while some portion of our operating expensesare incurred in British pounds and Norwegian kroner. Wetherefore typically have higher expenses than revenuedenominated in British pounds and Norwegian kroner.     In 2005 we started hedging a portion of our foreign currencyexposure related to operating expenses by entering into forwardcurrency exchange contracts. While we enter into these contractswith the purpose of reducing our exposure to changes in exchangerates, we do not account for the contracts as hedges.Consequently, all outstanding forward currency exchangecontracts are recorded at estimated fair value using the midrate and gains and losses are included in other financial items,net. As of December 31, 2005, we had open forward contractsto buy British pounds and Norwegian kroner amounting toapproximately $194 million with a fair value of$(7.2) million (loss), which has been recognized in ourstatements of operations. At December 31, 2004, we did nothave any open forward exchange contracts.     If British pounds had appreciated by a further 10% against theU.S. dollar at year-end, the fair value of the forwardcontracts on buying British pounds would have increased by$5.7 million. A similar 10% appreciation of Norwegiankroner against U.S. dollar would have increased the fairvalue of the forward contracts on buying Norwegian kroner by$15.2 million.     Substantially all of our debt is denominated inU.S. dollars.**Commodity risk**     In the operation of our seismic vessels we use substantialquantity of fuel. We are therefore exposed to changes in fuelprices. Based on our fuel consumption in 2005, if fuel priceswere to increase by 10%, our fuel costs would increase byapproximately $5 million. We do not hedge this exposure byusing derivatives.
83

Table of Contents
**ITEM 12.*****Description of Securities Other Than Equity    Securities***     Not applicable.**PART II****ITEM 13.*****Defaults, Dividend Arrearages and Delinquencies***     Not applicable.**ITEM 14.*****Material Modifications to the Rights of Security Holders    and Use of Proceeds***     Not applicable.**ITEM 15.*****Controls and Procedures***     Beginning in 2004 and through 2005, we have implemented ourSarbanes-Oxley Section 404 readiness project and havesignificantly improved our internal control environment. In ourassessment of our internal control over financial reporting forthe period relevant for the preparation of our 2005 financialstatements and at December 31, 2005, we have concluded thatthe material weaknesses identified in connection with the auditof our 2004 financial statements have been remediated. However,two significant control deficiencies remained as ofDecember 31, 2005 regarding the sufficiency of oursupervisory review procedures related to income tax provisionand regarding timely and sufficiently detailed research anddocumentation of certain significant accounting issues. Ourassessment also identified certain other control deficiencies.We believe that these deficiencies do not represent a materialweakness condition, either individually or in aggregate.     In September 2003, our independent registered public accountingfirm, Ernst & Young AS (“EY”), identifiedmaterial weaknesses regarding various elements of our system ofinternal control over financial reporting. A material weaknesscondition exists when significant control deficiencies, or acombination of control deficiencies, are present that results inmore than a remote likelihood that a material misstatement ofthe annual or interim financial statements will not be preventedor detected.     While we made considerable improvement in our internal controlover financial reporting during 2004, our assessment of theprogress made in addressing the material weaknesses identifiedin September 2003 indicated that, for the period relevant forthe preparation of our 2004 financial statements and atDecember 31, 2004, significant deficiencies that, in theaggregate, constituted a material weakness continued to existrelating to: •     the U.S. GAAP competency and procedures for timely and    complete identification of developments and transactions of a    non-routine nature that require specific accounting    consideration;  •     the sufficiency of supervisory review control activities in    parts of our company;  •     the sufficiency of procedures to capture and timely and    precisely accrue expenses for our Production operations and the    vessel operations of Marine Geophysical; and  •     the sufficiency of supervisory review and certain other    procedures related to income tax provision.     In May 2005, in connection with the audit of our 2004 financialstatements under U.S. GAAP, EY confirmed the continuationof these matters that, in the aggregate, they considered toconstitute a material weakness.     Acting under the supervision and guidance of our Audit Committeeand Board of Directors, our management worked to address theseidentified material weaknesses and significant deficiencies,including implementing our Sarbanes-Oxley Section 404readiness project. We recruited additional GAAP expertise tooversee our GAAP compliance and improved procedures foraccounting for unusual transactions. We also improved ourprocedures for capturing and assessing transactions of anon-routine nature and subsequent events; increased focus ontimely review, documentation and evaluation of account balancesand agreements; and strengthened the procedures for capturingoperating expenses and accruals related to our Productionoperations and vessel operations in Marine Geophysical. Toaddress the deficiency related to reporting of
84

Table of Contents
income taxes, we improved the control procedures for income taxaccounting, including allocation of responsibilities andstrengthened review procedures.     Despite significant improvements in the overall design andcontrols in relation to the preparation of financial statements,our assessment of the progress made for the period relevant tothe 2005 financial reporting indicated that significant controldeficiencies remained with respect to the sufficiency of oursupervisory review procedures related to income tax provisionand, in addition, that not all significant accounting issueswere documented and concluded upon timely with sufficient detailand technical reference, specifically regarding pension plansettlements and segment disclosures. A significant deficiencyexists when the timeliness and quality control procedures allowmore than a remote likelihood that a misstatement of thecompany’s annual financial statements that is more thaninconsequential may not be prevented or detected. EY issued aletter dated April 4, 2006 addressing these significantdeficiencies.     Our management, with the oversight of our Audit Committee andBoard of Directors, is committed to having proper internalcontrol over financial reporting. We believe that the actionsalready taken will continue to improve our internal control overfinancial reporting since many of these controls and remedialactions relate to people and processes that require time beforethey are fully effective. With regards to the significantdeficiencies discussed above, we implemented new improvedcontrol procedures and hired a technical resource before the2005 year-end financial reporting. We believe that ourprocedures have an adequate design quality, and we willimplement further personnel training and increased supervisionto remediate deficiencies in the operation of the procedures. Inaddition, management has developed remediation plans to addressother identified control deficiencies.     As required by SECRule 13a-15(b), wehave carried out an evaluation, under the supervision and withthe participation of our management, including our ChiefExecutive Officer and our Chief Financial Officer, of theeffectiveness of our disclosure control and procedures as ofDecember 31, 2005, the end of the period covered by thisannual report. Based on that evaluation, our Chief ExecutiveOfficer and our Chief Financial Officer concluded that ourdisclosure control and procedures were effective to ensure thatinformation required to be disclosed by us in the reports wefile or submit under the U.S. Securities Exchange Act of1934 was timely recorded, processed, summarized and reported asof December 31, 2005.     Beginning with the year ending December 31, 2006,Section 404 of the Sarbanes-Oxley Act will require us toinclude an internal control report of management with our annualreport onForm 20-F. Weexpect to continue to make changes in our internal control overfinancial reporting during our documentation and controlevaluation in preparation for compliance with Section 404of the Sarbanes-Oxley Act. As we implement remaining changes inour internal control and as we address requirements under theSarbanes-Oxley Act, we could identify additional deficiencies inour system of internal control over financial reporting thatwill require additional remedial efforts.     Because of the inherent limitations in all control systems, noevaluation of control can provide absolute assurance that allcontrol issues and instances of fraud will be or have beendetected. These inherent limitations include the realities thatjudgments in decision-making can be faulty and that breakdownscan occur because of simple error or mistake. The design of anysystem of control also is based in part upon assumptions aboutthe likelihood of future events, and there can be no assurancethat any design will succeed in achieving its stated goals underall potential future conditions. Over time, control may becomeinadequate because of changes in conditions, or the degree ofcompliance with the policies or procedures may deteriorate.Because of the inherent limitations in a cost-effective controlsystem, misstatements due to error or fraud may occur and not bedetected.**ITEM 16A.     *Audit CommitteeFinancial Expert***     Our Board of Directors has determined that each of FrancisGugen, Anthony Tripodo and Harald Norvik meets the definition ofan audit committee financial expert, as that term is defined forpurposes of Item 16A ofForm 20-F, andthat each is independent under applicable provisions of theSecurities Exchange Act of 1934 and New York Stock Exchangelisting standards.
85

Table of Contents
**ITEM 16B.     *****Code of Ethics***     We have adopted a Code of Conduct that applies to, among others,our principal executive officer, principal financial officer,principal accounting officer and persons performing similarfunctions. We have filed the code as an exhibit to this annualreport and posted it under the “About PGS” section ofour internet website at *www.pgs.com.***ITEM 16C.     *****Principal Accountant Fees and Services***     Under our Audit Committee Charter, the Audit Committee isresponsible (subject to approval by the Board of Directors) for: •     pre-approving all auditing services and permitted non-audit    services to be provided by our independent registered public    accounting firm and observing applicable limitations on engaging    the independent registered public accounting firm to perform the    specific non-audit services restricted by law or    regulations; and  •     to the extent it deems necessary or appropriate, retaining and    compensating independent legal, accounting or other advisors.     Under our pre-approval policy, the Audit Committee is requiredto pre-approve all audit, review or attest engagements andpermissible non-audit services to be performed by ourindependent registered public accounting firm, subject to, andin compliance with, the *de minimis*exception fornon-audit services described in applicable provisions of theSecurities Exchange Act of 1934 and applicable SEC rules. Allservices provided by EY in 2005 were pre-approved by theAudit Committee.     Aggregate fees through March 31, 2005 for professionalservices rendered by EY, including reimbursement ofout-of-pocket expenses,related to 2005, 2004 and 2003 were as follows:               **Years Ended December 31,**     **2005** **2004** **2003**         **(In thousands)**    Audit fees(a) $4,112  $4,453  $5,925     Audit-related fees(b)  163   42   114     Fees for tax services(c)  175   134   182     All other fees(d)  4   —   541               Total $4,454  $4,629  $6,762            (a)     Audit fees consisted of fees for audit services, which related    to the consolidated audit, statutory audits, accounting    consultations, subsidiary audits and related matters, and fees    for audit of fresh start reporting. Fees for 2005 are based on    estimates as of March 21, 2005. Fees for 2004 and 2003 have    been updated to reflect fees incurred after May 3, 2005    related to the 2004 and 2003 audits.    (b)    Audit-related fees consisted of fees for agreed upon procedures    and other attestation services.     (c)    Fees for tax services consisted of fees for tax services, tax    filing and compliance and reorganization.     (d)    Other fees consisted mainly of fees for assistance in connection    with restructuring, refinancing and due diligence performed by    banks in connection with our financial restructuring in 2003.
86

Table of Contents
**ITEM 16D.     *****Exemptions from the Listing Standards for Audit    Committees***     Not applicable.**ITEM 16E.     *****Purchases of Equity Securities by the Issuer and    Affiliated Purchasers***     None.**ITEM 17.*****Financial Statements***     Not applicable.**ITEM 18.*****Financial Statements*****Index to Consolidated Financial Statements**       **Page**   **Consolidated Financial Statements of Petroleum Geo-Services    ASA and Subsidiaries**        Report of Independent Registered Public Accounting Firm  F-2     Consolidated Balance Sheets as of December 31, 2005 and 2004  F-3     Consolidated Statements of Operations for the years ended    December 31, 2005 and 2004, the two months ended    December 31, 2003 (Successor) and the ten months ended    October 31, 2003 (Predecessor)  F-4     Consolidated Statements of Cash Flows for the years ended    December 31, 2005 and 2004, the two months ended    December 31, 2003 (Successor) and the ten months ended    October 31, 2003 (Predecessor)  F-5     Consolidated Statements of Changes in Shareholders’ Equity    for the years ended December 31, 2005 and 2004, the two    months ended December 31, 2003 (Successor)and the ten    months ended October 31,2003 (Predecessor)  F-6     Notes to Consolidated Financial Statements  F-7      We specifically incorporate by reference in response to thisitem the auditor’s report, the consolidated financialstatements and the notes to the consolidated financialstatements appearing onpages F-2 throughF-63.**ITEM 19.     *****Exhibits***       **Exhibit**    **Number**   **Description**      1.1     —     Articles of Association, as amended (unofficial English    translation)  2.1     —     Deposit Agreement, dated as of May 25, 1993, among    Petroleum Geo-Services ASA (the “Company”), Citibank,    N.A., as depositary (the “Depositary”), and all    holders from time to time of American Depositary Receipts issued    thereunder (incorporated by reference to Exhibit(a)(1) of    Post-Effective Amendment No. 1 to the Company’s    Registration Statement on Form F-6 (Registration    No. 33-61500))  2.2     —     First Amendment to Deposit Agreement, dated as of April 24,    1997, among the Company, the Depositary and all holders from    time to time of American Depositary Receipts issued thereunder    (incorporated by reference to Exhibit(a)(2) of the    Company’s Registration Statement on Form F-6    (Registration No. 333-10856))  2.3     —     Form of American Depositary Receipt (incorporated by reference    to filing under Rule 424(b)(3) relating to the    Company’s Registration Statements on Form F-6    (Registration No. 333-122046))     The Company and its consolidated subsidiaries are party toseveral debt instruments under which the total amount ofsecurities authorized does not exceed 10% of the total assets ofthe Company and its
87

Table of Contents
subsidiaries on a consolidated basis. Pursuant toparagraph 2(b)(i) of the instructions to the exhibits toForm 20-F, theCompany agrees to furnish a copy of such instruments to the SECupon request.        4.1     —     Contract of Employment dated 26 January 2006 between the Company    and Svein Rennemo  4.2     —     2004 CEO Bonus Scheme (incorporated by reference to    Exhibit 4.3 of the 2003 Form 20-F)  4.3     —     Credit Agreement, dated as of December 16, 2005, among the    Company, certain of its subsidiaries and the lender parties    thereto  8.1     —     Subsidiaries (included in Item 4 of the annual report)  11.1     —     Code of Conduct (incorporated by reference to Exhibit 11.1    of the 2004 Form 20-F)  12.1     —     Certification of Chief Executive Officer pursuant to    Section 302 of the Sarbanes-Oxley Act of 2002 and    Rule 13a-14(a) of the Securities Exchange Act of 1934  12.2     —     Certification of Chief Financial Officer pursuant to    Section 302 of the Sarbanes-Oxley Act of 2002 and    Rule 13a-14(a) of the Securities Exchange Act of 1934  13.1     —     Certification of the Chief Executive Officer and the Chief    Financial Officer pursuant to Section 906 of the    Sarbanes-Oxley Act of 2002 and Rule 13a-14(b) of the    Securities Exchange Act of 1934  15.1     —     Audit Committee Charter (incorporated by reference to    Exhibit 15.1 of the 2004 Form 20-F)  15.2     —     Remuneration Committee Charter (incorporated by reference to    Exhibit 15.2 of the 2004 Form 20-F) 15.3     —     Consent of Ernst & Young AS
88

Table of Contents
**SIGNATURES**     The registrant hereby certifies that it meets all of therequirements for filing onForm 20-F and thatit has duly caused and authorized the undersigned to sign thisannual report on its behalf.     PETROLEUM GEO-SERVICES ASA By:     /s/ GOTTFRED LANGSETH           Gottfred Langseth *Chief Financial Officer*Date: April 5, 2006
89

Table of Contents
**INDEX TO CONSOLIDATED FINANCIAL STATEMENTS**       **Page**   **Consolidated Financial Statements of Petroleum Geo-Services    ASA and Subsidiaries**         Report of Independent Registered Public    Accounting Firm  F-2      Consolidated Balance Sheets as of    December 31, 2005 and 2004  F-3      Consolidated Statements of Operations for    the years ended December 31, 2005 and 2004, the two months    ended December 31, 2003 (Successor) and the ten months    ended October 31, 2003 (Predecessor)  F-4      Consolidated Statements of Cash Flows for    the years ended December 31, 2005 and 2004, the two months    ended December 31, 2003 (Successor) and the ten months    ended October 31, 2003 (Predecessor)  F-5      Consolidated Statements of Changes in    Shareholders’ Equity for the years ended December 31,    2005 and 2004, the two months ended December 31, 2003    (Successor) and the ten months ended October 31, 2003    (Predecessor)  F-6      Notes to Consolidated Financial    Statements  F-7 
F-1

Table of Contents
**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**To the Board of Directors and Shareholders ofPETROLEUM GEO-SERVICES ASA:     We have audited the accompanying consolidated balance sheets ofPetroleum Geo-Services ASA and subsidiaries as ofDecember 31, 2005 and 2004, and the related consolidatedstatements of operations, changes in shareholders’ equity(deficit), and cash flows for each of the two years in theperiod ended December 31, 2005 and the two months endedDecember 31, 2003 (Successor), and for the ten months endedOctober 31, 2003 (Predecessor). These financial statementsare the responsibility of the Company’s Board of Directorsand management. Our responsibility is to express an opinion onthese financial statements based on our audits.     We conducted our audits in accordance with the standards of thePublic Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements arefree of material misstatement. We were not engaged to perform anaudit of the Company’s internal control over financialreporting. Our audits included consideration of internal controlover financial reporting as a basis for designing auditprocedures that are appropriate in the circumstances, but notfor the purpose of expressing an opinion on the effectiveness ofthe Company’s internal control over financial reporting.Accordingly we express no such opinion. An audit also includesexamining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements, assessing theaccounting principles used and significant estimates made bymanagement, as well as evaluating the overall financialstatement presentation. We believe that our audits provide areasonable basis for our opinion.     In our opinion, the financial statements referred to abovepresent fairly, in all material respects, the consolidatedfinancial position of Petroleum Geo-Services ASA andsubsidiaries as of December 31, 2005 and 2004, and theconsolidated results of their operations and their cash flowsfor each of the two years in the period ended December 31,2005 and the two months ended December 31, 2003(Successor), and for the ten months ended October 31, 2003(Predecessor) in conformity with U.S. generally acceptedaccounting principles.     As discussed in Note 3 to the consolidated financialstatements, the Company emerged from bankruptcy and effectiveNovember 1, 2003, adopted fresh-start reporting pursuant toAmerican Institute of Certified Public Accountants Statement ofPosition 90-7,*“Financial Reporting by Entities in Reorganization Underthe Bankruptcy Code”*. As a result, the consolidatedfinancial statements of the Successor are presented on adifferent basis than those of the Predecessor and, therefore,are not comparable.     As discussed in Note 2 of the consolidated financialstatements, the Predecessor changed its accounting principles toadopt, as of January 1, 2003, the provisions of Statementof Financial Accounting Standards No. 143,*“Accounting for Asset Retirement Obligations.”*     /s/ Ernst & Young    ASOslo, NorwayApril 4, 2006
F-2

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****CONSOLIDATED BALANCE SHEETS**             **December 31,**     **2005** **2004**       **(In thousands of dollars)****ASSETS**    Cash and cash equivalents $121,464  $132,942     Restricted cash  14,494   25,477     Shares available for sale and investment in securities  13,222   9,689     Accounts receivable, net  213,621   161,283     Unbilled and other receivables  67,785   40,561     Other current assets  67,737   60,506              Total current assets  498,323   430,458     Property and equipment, net  972,018   1,009,008     Multi-client library, net  146,171   244,689     Oil and natural gas assets, net  639   71,491     Restricted cash  10,014   10,014     Deferred tax assets  20,000   —     Investments in associated companies  5,935   5,720     Other long-lived assets  40,086   44,659     Other intangible assets, net  24,386   36,114              Total assets $1,717,572  $1,852,153         **LIABILITIES AND SHAREHOLDERS’ EQUITY**    Short-term debt and current portion of long-term debt $24,406  $19,790     Current portion of capital lease obligations  20,495   25,583     Accounts payable  74,285   81,910     Accrued expenses  164,327   115,256     Income taxes payable  26,318   11,870     Deferred tax liabilities  1,055   761              Total current liabilities  310,886   255,170     Long-term debt  922,134   1,085,190     Long-term capital lease obligations  13,205   33,156     Deferred tax liabilities  497   35,118     Other long-term liabilities  140,790   219,650              Total liabilities  1,387,512   1,628,284            Minority interest in consolidated subsidiaries  785   962     Shareholders’ equity:             Common stock: 60,000,000 shares authorized, issued and    outstanding, par value NOK 10, at December 31, 2005    and 20,000,000 shares authorized, issued and outstanding,    par value NOK 30, at December 31, 2004  85,714   85,714      Additional paid-in capital  277,427   277,427      Accumulated deficit  (32,105)  (144,683)     Accumulated other comprehensive (loss) income  (1,761)  4,449              Total shareholders’ equity  329,275   222,907              Total liabilities and shareholders’ equity $1,717,572  $1,852,153        The accompanying notes are an integral part of theseconsolidated financial statements.
F-3

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****CONSOLIDATED STATEMENTS OF OPERATIONS**                       **Predecessor**  **Successor Company** **Company**         **Two Months** **Ten Months**  **Years Ended December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars, except share data)**    Revenues services $1,159,584  $945,334  $162,827  $849,767     Revenues products  36,742   184,134   9,544   112,097                    Total revenues  1,196,326   1,129,468   172,371   961,864                  Cost of sales services(a)  678,346   587,912   95,044   454,396     Cost of sales products(a)  22,304   44,838   1,910   33,382     Exploration costs  1,438   16,326   —   —     Depreciation and amortization  259,355   368,362   55,699   301,576     Research and development costs  9,918   3,419   598   2,024     Selling, general and administrative costs(a)  67,420   64,816   7,366   44,326     Impairment of long-lived assets  4,575   —   —   95,011     Net gain on sale of subsidiaries  (156,382)  —   —   —     Other operating (income) expense, net  (26,095)  8,112   1,052   21,324                    Total operating expenses  860,879   1,093,785   161,669   952,039                  Operating profit  335,447   35,683   10,702   9,825     Other income (expense):                     Income from associated companies  276   668   200   774      Interest expense  (96,356)  (110,811)  (16,870)  (98,957)     Debt redemption and refinancing costs  (107,315)  —   —   —      Other financial items, net  5,918   (10,861)  (4,264)  (1,472)                137,970   (85,321)  (10,232)  (89,830)    Reorganization items:                     Gain on debt discharge  —   —   —   1,253,851      Fresh-start adoption  —   —   —   (532,268)     Cost of reorganization  —   (3,498)  (3,325)  (52,334)                 Income (loss) before income tax expense (benefit) and minority    interest  137,970   (88,819)  (13,557)  579,419     Income tax expense (benefit)  21,827   48,019   (3,849)  21,911     Minority interest  4,065   940   110   570                  Income (loss) from continuing operations before cumulative    effect of change in accounting principles  112,078   (137,778)  (9,818)  556,938     Income (loss) from discontinued operations, net of tax  500   3,048   (135)  (2,282)                 Income (loss) before cumulative effect of change in accounting    principles  112,578   (134,730)  (9,953)  554,656     Cumulative effect of change in accounting principles, net of tax  —   —   —   2,389                    Net income (loss) $112,578  $(134,730) $(9,953) $557,045                  Basic and diluted income (loss) from continuing operations per    share $1.87  $(2.30) $(0.17) $5.39     Income (loss) from discontinued operations, net of tax  0.01   0.05   —   (0.02)    Cumulative effect of change in accounting principle, net of tax  —   —   —   0.02                  Basic and diluted net income (loss) per share $1.88  $(2.25) $(0.17) $5.39                  Weighted average basic and diluted shares outstanding  60,000,000   60,000,000   60,000,000   103,345,987              Note:    (a)    Excluding depreciation and amortization, which is shown    separately.The accompanying notes are an integral part of theseconsolidated financial statements.
F-4

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****CONSOLIDATED STATEMENTS OF CASH FLOWS**                        **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**             **(In thousands of dollars)**  **Cash flows (used in) provided by operating activities:**                     Net income (loss) $112,578  $(134,730) $(9,953) $557,045      Adjustments to reconcile net income (loss) to net cash provided    by operating activities:                      Depreciation and amortization charged to expense  259,355   368,362   55,699   301,576       Exploration costs (dry well expensed)  —   11,438   —   —       Non-cash impairments, loss (gain) on sale of subsidiaries    and change in accounting principles, net  (151,807)  —   32   92,622       Non-cash effect of fresh start adoption  —   —   —   534,085       Non-cash effect of restructuring  —   —   —   (1,253,851)      Non-cash write-off of deferred debt costs and issue discounts  363   —   —   13,152       Non-cash other operating (income) expense, net  (26,095)  —   —   —       Premium on debt redemption and cost of refinancing expensed  106,952   —   —   —       Cash effects related to discontinued operations  —   —   157   3,185       Provision for deferred income taxes  10,965   27,263   (5,801)  (1,918)      (Increase) decrease in accounts receivable, net  (52,338)  (33,577)  34,582   6,848       Increase (decrease) in accounts payable  (7,625)  25,592   19,391   (18,587)      Loss on sale of assets  1,893   4,128   —   6,193       Net (increase) decrease in restricted cash  1,342   15,646   3,824   (23,728)      Other items  23,473   (1,750)  (35,761)  (51,674)                    Net cash provided by operating activities  279,056   282,372   62,170   164,948              **Cash flows (used in) provided by investing activities:**                     Investment in multi-client library  (55,667)  (41,140)  (9,461)  (81,142)     Capital expenditures  (90,490)  (148,372)  (15,985)  (42,065)     Capital expenditures on discontinued operations  —   —   —   (118)     Proceeds from sales of subsidiaries, net  155,356   2,035   —   50,115      Other items, net  1,300   4,031   357   3,478                     Net cash (used in) provided by investing activities  10,499   (183,446)  (25,089)  (69,732)             **Cash flows (used in) provided by financing activities:**                     Proceeds from issuance of long-term debt  850,000   —   —   —      Repayment of long-term debt  (1,009,152)  (24,167)  (4,850)  (70,496)     Principal payments under capital leases  (25,700)  (22,930)  (3,025)  (22,352)     Net increase (decrease) in bank facility and short-term debt  712   1,962   —   (48)     Distribution to creditors under the restructuring agreement  —   (22,660)  (17,932)  —      Premium on debt redemption, deferred loan costs and    reorganization fees  (116,813)  (3,488)  —   —                     Net cash used in financing activities  (300,953)  (71,283)  (25,807)  (92,896)                  Effect of exchange rate changes on cash  (80)  74   —   14                   Net increase (decrease) in cash and cash equivalents  (11,478)  27,717   11,274   2,334      Cash and cash equivalents at beginning of period  132,942   105,225   93,951   91,617                     Cash and cash equivalents at end of period $121,464  $132,942  $105,225  $93,951              The accompanying notes are an integral part of theseconsolidated financial statements.Supplementary cash flow information is included in Note 28.
F-5

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’EQUITY**                                   **Accumulated**    **Common Stock** **Additional**   **Other**      **Paid-In** **Accumulated** **Comprehensive** **Shareholders’**  **Number** **Par value** **Capital** **Deficit** **Income (Loss)** **Equity**               **(In thousands of dollars, except for share data)****Predecessor Company:**                            Balance at December 31, 2002  103,345,987   71,089   1,225,115   (1,458,097)  (30,361)  (192,254)     Comprehensive income (loss):                              Net income              557,045   —   557,045       Other comprehensive income (loss)              —   (1,650)  (1,650)                         Total comprehensive income (loss)              557,045   (1,650)  555,395     Reorganization items  (103,345,987)  (71,089)  (1,225,115)  901,052   32,011   (363,141)                       Balance at October 31, 2003  —  $—  $—  $—  $—  $—                    **Successor Company:**                             Issuance of common stock  20,000,000  $85,714  $277,427  $—  $—  $363,141      Comprehensive income (loss):                              Net loss              (9,953)  —   (9,953)      Other comprehensive income              —   446   446                          Total comprehensive income (loss)              (9,953)  446   (9,507)                       Balance at December 31, 2003  20,000,000   85,714   277,427   (9,953)  446   353,634      Comprehensive income (loss):                              Net loss              (134,730)  —   (134,730)      Other comprehensive income              —   4,003   4,003                          Total comprehensive income (loss)  —   —   —   (134,730)  4,003   (130,727)                       Balance at December 31, 2004  20,000,000   85,714   277,427   (144,683)  4,449   222,907      Share split June 8, 2005  40,000,000                          Comprehensive income (loss):                              Net income              112,578   —   112,578       Other comprehensive (loss)              —   (6,210)  (6,210)                         Total comprehensive income (loss)  —   —   —   112,578   (6,210)  106,368                        Balance at December 31, 2005  60,000,000  $85,714  $277,427  $(32,105) $(1,761) $329,275                         The Company’s ability to pay dividends is among otherthings limited to free equity as defined in Norwegian corporatelaw and measured on the basis of the unconsolidated financialstatements of the parent company, Petroleum Geo-Services ASA, asprepared in accordance with generally accepted accountingprinciples in Norway. At December 31, 2005, PetroleumGeo-Services ASA had $595,556,580 (equivalent to Norwegiankroner 4,028,291,106) of free equity.     The components of Accumulated Other Comprehensive Income (loss)are as follows:                        **Net Foreign** **Net** **Net**   **Accumulated**  **Currency** **Unrealized** **Gain (Loss)** **Pension** **Other**  **Translation** **Gain (Loss)** **Cash Flow** **Minimum** **Comprehensive**  **Adjustments** **Investments** **Hedges** **Liability** **Income (Loss)**             **(In thousands of dollars)****Predecessor Company:**                        Balance at December 31, 2002 $(26,347) $—  $—  $(4,014) $(30,361)     Ten months ended October 31, 2003  1,580   —   —   (3,230)  (1,650)    Reorganization items  24,767   —   —   7,244   32,011                     Balance at October 31, 2003 $—  $—  $—  $—  $—                 **Successor Company:**                         Two months ended December 31, 2003 $446  $—  $—  $—  $446                     Balance at December 31, 2003  446   —   —   —   446      Year ended December 31, 2004  (1,667)  5,889   —   (219)  4,003                     Balance at December 31, 2004  (1,221)  5,889   —   (219)  4,449      Year ended December 31, 2005  (2,534)  (1,837)  (1,628)  (211)  (6,210)                    Balance at December 31, 2005 $(3,755) $4,052  $(1,628) $(430) $(1,761)                The accompanying notes are an integral part of theseconsolidated financial statements.
F-6

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****NOTE 1 —****General Information about the Company and Basis of    Presentation**     Petroleum Geo-Services ASA (“PGS ASA”) is a publiclimited liability company established under the laws of theKingdom of Norway in 1991. Unless stated otherwise, referencesherein to the “Company” and “PGS” refer toPetroleum Geo-Services ASA and its majority-owned subsidiariesand affiliates, companies in which it has and controls amajority voting interest.     PGS is a technologically focused oilfield service companyprincipally involved in providing geophysical services worldwideand floating production services in the North Sea. Globally, PGSprovides a broad range of geophysical and reservoir services,including seismic data acquisition, processing andinterpretation and field evaluation. In the North Sea, theCompany owns and operates four harsh environment floatingproduction, storage and offloading vessels (“FPSOs”).The Company’s headquarters are at Lysaker, Norway. Seefurther discussion of the Company’s services inNote 27.     The Company considers its primary basis of accounting to be USgenerally accepted accounting principles (“US GAAP”),and has prepared these consolidated financial statements inaccordance with those principles. PGS is also required toprepare and publish statutory accounts in Norway using Norwegiangenerally accepted accounting principles (“NorwegianGAAP”). Norwegian GAAP differs materially from US GAAP.     As more fully described in Note 24, the Company sold itswholly owned oil and natural gas subsidiary Pertra AS in March2005 and entered into an agreement to sell its wholly ownedsubsidiary PGS Reservoir AS in August 2005. The financialresults of operations and cash flows for these subsidiaries areincluded in the consolidated statements of operations andconsolidated cash flows for the periods up to the sales dates.The operations are not presented as discontinued due tocontinuing involvement through the lease of *PetrojarlVarg*.     The Company sold its software company PGS Tigress (UK) Ltd.in December 2003 and its Atlantis subsidiary in February 2003.The financial position and results of operations and cash flowsfor these subsidiaries have been presented as discontinuedoperations as of December 31, 2003 and for the year endedDecember 31, 2003. Discontinued operations and related cashflows for the years ended December 31, 2005 and 2004include additional proceeds that were contingent on certainevents related to discontinued operations sold in 2002(Production Services). See Note 24 for additionalinformation of these disposals.     Upon emergence from Chapter 11, the Company, adopted“fresh-start” reporting as required under theprovisions of AICPA Statement of Position (“SOP”)90-7, *“Financial Reporting by Entities in Reorganizationunder the Bankruptcy Code,”*effective November 1,2003. Adoption of fresh-start reporting results in companiesreflecting the fair value of the business emerging frombankruptcy (the “reorganization value”) in the postfresh-start financial statements, and is required when theholders of the voting common shares immediately before thefiling and confirmation of the reorganization plan received lessthan 50% of the voting shares of the emerging company and whenthe company’s reorganization value is less than itspost-petition liabilities and allowed claims. Since theseconditions were met, the Company adopted fresh-start reporting,and as a result, in these consolidated financial statements, theterms “Successor” and “Successor Company”refer to PGS’ financial statements subsequent to theemergence from Chapter 11 and the terms“Predecessor” and “Predecessor Company”refer to PGS’ financial statements for periods up to theemergence from Chapter 11 including the effect of thereorganization plan. The adoption of fresh-start reportingreflects the Company’s reorganization value as its newbasis in accounting, new accounting pronouncements it wasrequired to adopt with fresh-start reporting and changes incertain of its accounting policies. The Company’s financialinformation in Successor Company periods should not be comparedto financial information from Predecessor Company periods asthey are not comparable.
F-7

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)****NOTE 2 —****Summary of Significant Accounting Policies*****Consolidation and Equity Investments.***     The Company’s consolidated financial statements include alltransactions of PGS ASA, its wholly owned and majority ownedsubsidiaries that it controls and equity investments.Subsidiaries are consolidated in the financial statements fromthe point in time when the Company gains control. Acquisitionsare accounted for using the purchase method of accounting.Acquisition prices are assigned to the assets and liabilities ofthe subsidiaries using their fair value at the date ofacquisition. Any excess of purchase cost over fair value ofassets and liabilities is recorded as goodwill. Allinter-company transactions and balances have been eliminated inthe consolidation. In those cases where the subsidiaries are notwholly owned, the minority interests are separately presented inthe consolidated statements of operations and consolidatedbalance sheets.     Investments in associated companies in which the Company has anownership interest equal to or greater than 20% but equal to orless than 50% and where the Company has the ability to exercisesignificant influence are accounted for using the equity method.     The Company periodically reviews its investments in associatedcompanies to determine if a loss in value has occurred that isother-than-temporary. PGS considers all available information,including the recoverability of its investment, the earnings andnear-term prospects of the investee company, factors related tothe industry, conditions of the investee company and theability, if any, to influence the management of the investeecompany.     Shares available for sale and investments in securities with anavailable market value are carried at fair value at each balancesheet date, with unrealized holding gains and losses reported in“unrealized gain (loss) investments” in othercomprehensive income until realized.***Variable Interest Entities.***     In January 2003, the Financial Accounting Standards Board(“FASB”) issued FASB Interpretation No. 46(“FIN 46”) *“Consolidation of VariableInterest Entities”*, and in December 2003, the FASBissued a revised FIN 46 (“FIN 46R”), whichaddress when a company should include in its financialstatements the assets, liabilities and activities of anotherentity. FIN 46R requires consolidation of a variableinterest entity (“VIE”) if the reporting entity issubject to a majority of the risk of loss from the VIE’sactivities or is entitled to receive a majority of theVIE’s residual returns or both. The consolidationrequirements of FIN 46R apply immediately to VIEs createdafter January 31, 2003, and to all other existingstructures commonly referred to as special purpose entities. Theconsolidation requirements applied to VIEs that were createdprior to January 31, 2003 and apply to the Company upon theadoption of fresh-start reporting.     The Company has concluded that it is the primary beneficiary oftwo VIEs: DMNG PGS AS and Walter Herwig AS. Accordingly, theseentities are consolidated in the Successor’s financialstatements. Walter Herwig AS had become a 100% owned subsidiaryof the Company by December 31, 2003, and merged with PGSGeophysical AS, also a wholly owned subsidiary, in 2005. Theoperations, assets and liabilities of DMNG PGS AS are notmaterial to the Company’s financial statements.     In addition, the Company has considered its UK leases that wereentered into before 2003 (see Note 20) in relation toFIN 46R. As part of the evaluation process, the Company hasrequested further information about the lessor entities,including information related to their other assets andcontractual arrangements. However, the Company has no rightsunder its agreements with the lessor entities to request orreceive such information, and the lessor entities (or theirowners) have denied the Company access to any such information.Accordingly, the Company has not been able to affirmativelydetermine if any of the lessor entities are in fact VIEs, and ifany are VIEs, who the primary beneficiary would be. Accordingly,none of these entities are consolidated.
F-8

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)*****Discontinued Operations.***     Subsidiaries that are either held for sale or discontinued arereported as discontinued operations. Revenues and expenses areexcluded from revenue and expenses of the Company and reportedseparately as a one line item in the consolidated statement ofoperations, net of tax. Assets and liabilities are presented asseparate line items in the consolidated balance sheets. Forfurther details about subsidiaries that we have sold oroperations that we have discontinued, see Note 24.***Use of Estimates.***     The preparation of financial statements in accordance withU.S. GAAP requires management to make estimates,assumptions and judgments that affect the reported amounts ofassets and liabilities and the disclosure of contingentliabilities. In many circumstances, the ultimate outcome relatedto the estimates, assumptions and judgments may not be known forseveral years after the preparation of the financial statements.Actual amounts may differ materially from these estimates due tochanges in general economic conditions, changes in laws andregulations, changes in future operating plans and the inherentimprecision associated with estimates.***Cash and Cash Equivalents.***     The carrying amounts of cash and cash equivalents approximatefair value. Cash and cash equivalents include demand depositsand all highly liquid financial instruments purchased withmaturities of three months or less.     Cash and cash equivalents that are restricted from theCompany’s use are disclosed separately in the consolidatedbalance sheets and are classified as current or long-termdepending on the nature of the restrictions. Such restrictionsprimarily relate to cash collateral for bid or performancebonds, employee tax withholdings and restricted deposits undercontracts. Restricted cash related to bid or performance bondsamounted to $2.3 million at December 31, 2005 and$11.7 million at December 31, 2004.***Foreign Currency Translation.***     The Company’s reporting currency is the U.S. dollar asit is the functional currency for substantially all of itsoperations throughout the world.     The financial statements of non-U.S. subsidiaries using theirrespective local currency as their functional currency aretranslated using the current exchange rate method. Under thecurrent exchange rate method, assets and liabilities aretranslated at the rate of exchange in effect at period end;share par value and paid-in capital are translated at historicalexchange rates; and revenue and expenses are translated at theaverage rates of exchange in effect during the period.Translation adjustments, net of tax, are recorded as a separatecomponent of shareholders’ equity.***Operating and Capital Leases.***     The Company has significant operating lease arrangements in allof its operating segments and also has some capital leasearrangements for land seismic equipment and UK leases forvessels (see “UK Leases” below). Capital leases arelease arrangements in which the substantial financial risk andcontrol, but not ownership, of the assets is transferred fromthe lessor to the Company.     The Company accounts for capital lease arrangements as if theCompany had acquired the assets, and the present value of thefuture lease payments is accounted for as liabilities. Theassets are depreciated over the expected useful lives or therelated lease terms, whichever is shorter.
F-9

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)*****UK Leases.***     The Company has entered into vessel lease arrangements in theUnited Kingdom (“UK leases”) relating to five of itsRamform-design seismic vessels, its FPSO vessel *PetrojarlFoinaven*and the topside production equipment for its FPSOvessel *Ramform Banff*(see Note 20). Generally, underthe leases, UK financial institutions (“Lessors”)acquired the assets from third parties and the Company leasedthe assets from the Lessors under long-term charters that givethe Company the option to purchase the assets for a bargainpurchase price at the end of the charter periods. The Lessorsclaims tax depreciation (capital allowances) on the capitalexpenditures that were incurred for the acquisition of theleased assets. The Company indemnified the Lessors for the taxconsequence resulting from changes in tax laws or interpretationof such laws or adverse rulings by authorities and forvariations in actual interest rates from those assumed in theleases.     Due to the nature of the charters, the Company accounts forthese leases as capital leases. The Company legally defeased itsfuture charter obligations for the assets by making up-front,lump sum payments to unrelated large institutional banks(“Payment Banks”), which then assumed theCompany’s liability for making the periodic payments dueunder the long-term charters (the “Defeased RentalPayments”) and termination sum obligations under theagreements. The Company has no rights to the amounts paid toPayment Banks. Due to the assumption of the charter paymentobligations by the Payment Banks, the Lessors legally releasedthe Company as the primary obligor under the charters.Accordingly, the Company accounted for the release as aderecognition of the capital lease obligations with respect tothese UK leases.     At the date that the Company executed any UK lease, the Companytreated the excess of the capitalized asset value over theamount required to legally defease the charter obligations as adeferred gain. The deferred gain related to indemnification fortax contingencies and for changes in future interest rates. Theportion of the deferred gain relating to changes in interestrates was amortized over the term of the respective leases up tothe date of adoption of fresh start reporting. The portion ofthe deferred gain relating to tax contingencies was recognizedin income in accordance with Emerging Issues Task Force(“EITF”) Issue 89-20, *“Accounting for CrossBorder Tax Benefit Leases,”* when the Company determinedthat the likelihood of the indemnifications becoming effectivewas remote.     The Defeased Rental Payments are based on assumed Sterling LIBORrates between 8% and 9% per annum (the “AssumedInterest Rates”). If actual interest rates are greater thanthe Assumed Interest Rates, the Company receives rental rebates.Conversely, if actual interest rates are less than the AssumedInterest Rates, the Company is required to pay rentals in excessof the Defeased Rental Payments (the “Additional RequiredRental Payments”). Such payments are made annually orsemi-annually and are recorded on a straight-line basis as otherfinancial items, net.     Effective November 1, 2003, the Company adopted fresh-startreporting and recorded a liability equal to the fair value ofthe future Additional Required Rental Payments. Such fair valuewas estimated at the net present value of the AdditionalRequired Rental Payments based on forward market rates forSterling LIBOR and an 8% per annum discount rate. Thisliability, which is amortized based on future rental payments,amounted to 30.5 million British pounds (approximately$51.6 million) at November 1, 2003, $24.6 millionBritish pounds (approximately $47.2 million) atDecember 31, 2004 and 22.0 million British pounds(approximately $38.1 million) at December 31, 2005.     For fresh-start reporting purposes, the Company estimated andrecorded the fair value of the specific tax exposure related tothe defeased UK leases noted above using a probability-weightedanalysis and a range of possible outcomes. The Company recordeda 16.7 million British pounds (approximately$28.3 million) liability as of November 1, 2003 inaccordance with the requirements ofSOP 90-7. AtDecember 31, 2004, this liability amounted to approximately$32.1 million. The Company releases applicable portions ofthis liability if and when the UK Inland Revenue accepts thelessors’ claims for capital allowances under each lease. In2005 the Company released 9.4 million British pounds(approximately $17.2 million) of the liability.
F-10

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**The remaining recorded liability as at December 31, 2005 is7.3 million British pounds (approximately$12.7 million) (see Note 20).***Receivables Credit Risk.***     The Company’s trade receivables are primarily frommultinational integrated oil companies and independent oil andnatural gas companies, including companies owned in whole or inpart by foreign governments. The Company manages its exposure tocredit risk through ongoing credit evaluations of customers andhas provided for potential credit losses through an allowancefor doubtful accounts. The allowance for doubtful accountsreflects management’s best estimate of probable lossesinherent in accounts receivable from trade customers and isbased on a number of factors consisting mainly of aging ofaccounts, historical experience, customer concentration,customer creditworthiness and current industry and economictrends. The Company does not believe that exposure toconcentrations of credit risk is likely to have a materialadverse impact on its financial position or results ofoperations.***Property and Equipment.***     Property and equipment are stated at cost less accumulateddepreciation, amortization and impairment charges. Depreciationand amortization are calculated based on cost less estimatedsalvage values using the straight-line method for all propertyand equipment, excluding leasehold improvements and capitalleases, which are amortized over the asset life or lease term,whichever is shorter.     The estimated useful lives for property and equipment for thePredecessor and Successor are as follows:           **Successor** **Predecessor**  **Company** **Company**  **Years** **Years**         Seismic vessels  20-25   20-30     Seismic and operations computer equipment  3-15   3-10     FPSO vessels and equipment  25-30   20-30     Buildings and related leasehold improvements  1-30   1-30     Fixture, furniture, fittings and office computers  3-5   3-5      Expenditures for major property and equipment that have aneconomic useful life of at least one year are capitalized asindividual assets and depreciated over their useful lives.Maintenance and repairs, including periodic maintenance andclass surveys for FPSOs and seismic vessels, are expensed asincurred. The Company capitalizes the applicable portion ofinterest costs to major capital projects. When property andequipment are retired or otherwise disposed of, the related costand accumulated depreciation are removed from the accounts, andany resulting gain or loss is included in the results ofoperations.     Significant spare parts are capitalized with the asset to whichthey pertain, while other spare parts, consumables and bunkersare classified as other current assets and stated at the lowerof cost and market.***Multi-Client Library.***     The multi-client library consists of seismic data surveys to belicensed to customers on a nonexclusive basis. Costs directlyincurred in acquiring, processing and otherwise completingseismic surveys are capitalized into the multi-client library,including the applicable portion of interest costs. The cost ofthe multi-client library is reduced by the amounts related toreduction of deferred tax asset valuation allowances establishedat fresh-start accounting. (For a further description, see“Income Taxes” below and Note 21.) Prior to itsadoption of fresh-start reporting, the Company also capitalizedcertain indirect costs and other associated costs that could beattributed to the projects, including cost of relocating crews(steaming) between surveys and the
F-11

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**cost of yard stays. Subsequent to the adoption of fresh-startreporting, the Company no longer capitalizes such indirect costs.     The Company records its investment in multi-client library in amanner consistent with its capital investment and operatingdecision analysis, which generally results in each component ofthe multi-client library being recorded and evaluatedseparately. Projects that are in the same political regime, withsimilar geological traits and that are marketed collectively arerecorded and evaluated as a group by year of completion(currently applies to certain surveys in Brazil and the Gulf ofMexico).     Amortization of the multi-client library is generally recordedin proportion to revenue recognized to date as a percentage ofthe total expected revenue. In determining the annualamortization rates applied to the multi-client library,management considers expected future sales and marketdevelopments and past experience. These expectations includeconsideration of geographic location, prospects, political risk,exploration license periods and general economic conditions.Management updates, at least annually, the total expectedrevenue for each survey or group of surveys of the multi-clientlibrary. Because of the inherent difficulty in estimating futuresales and market developments, it is possible that theamortization rates could deviate significantly from year toyear. To the extent that such revenue estimates, or theassumptions used to make those estimates, prove to be higherthan actual revenue, the Company’s future operations willreflect lower profitability due to increased amortization ratesapplied to the multi-client library in later years, and themulti-client library may also become subject to minimumamortization and/or impairment. Effective upon adoption offresh-start reporting, for purposes of streamlining theaccounting method of amortization, on an annual basis theCompany categorizes its multi-client surveys into threeamortization categories with amortization of 90%, 75% or 60% ofsales amounts. Classification of a project into a rate categoryis based on the ratio of its remaining net book value to itsremaining sales estimates. Each category therefore includessurveys as to which the remaining book value as a percentage ofremaining estimated sales is less than or equal to theamortization rate applicable to that category.     An integral component of amortization of the multi-clientlibrary is the minimum amortization policy. Under this policy,the book value of each survey or group of surveys of themulti-client library is reduced to a specified percentage byyear-end, based on the age of each survey or group of surveys inrelation to their year of completion. This requirement isapplied each year-end regardless of future revenue estimates forthe multi-client library survey or group of surveys. Thespecified percentage generates the maximum permitted book valuefor each multi-client library survey or group of surveys as theproduct of the percentage multiplied by the original cost of themulti-client library survey or group of surveys at therespective period end. Any additional or “minimum”amortization charges required are then determined through acomparison of the remaining book value to the maximum permittedbook value allowed for each survey or group of surveys in themulti-client library.     Effective with adoption of fresh-start reporting, the Companyrevised the minimum amortization period from eight years formarine surveys and five years for onshore surveys to five yearsfor both marine and onshore projects from the end of the year ofcompletion (the year when the project is completed and processeddata is ready and available for use) and three years forderivative processed projects (processing or reprocessing thatcreates data that can be marketed and sold as an addition to theexisting library) from the end of the year of completion.Existing marine surveys were accorded a transition profile basedon sales forecasts used to compute their fair value.
F-12

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     The specified percentages used to determine the maximum bookvalue of multi-client library components are summarized asfollows:                       **Successor** **Predecessor Company**  **Company** **% of Total Cost**  **% of Total Cost**      **Marine** **Marine**    **5-Year** **3-Year** **Components** **Components** **Land****Calendar Year** **Profile** **Profile** **(Excluding Brazil)** **(Brazil)** **Components**               Year 1  80%   66%   100%   100%   100%     Year 2  60%   33%   70%   92%   60%     Year 3  40%   0%   55%   76%   40%     Year 4  20%       40%   50%   20%     Year 5  0%       30%   43%   0%     Year 6          20%   34%         Year 7          10%   20%         Year 8          0%   0%          In addition, effective January 1, 2004, the Companyclassifies as amortization expense in its consolidatedstatements of operations any write-downs of individualmulti-client surveys that are based on changes in projectspecific expectations and that are not individually material.The Company expects this additional, non-sales related,amortization expense to occur regularly because the Companyevaluates each individual project at least annually forimpairment or when specific indicators exist. The Companyclassifies as impairment in its consolidated statements ofoperations write-downs related to fundamental changes inestimates affecting a larger part of the Company’smulti-client library that are material. Prior to 2004 theCompany classified as impairment expense all write-downs ofmulti-client library.***Other Intangible Assets.***     Other intangible assets relate to direct costs of softwareproduct for internal use, patents, royalties and licenses.Substantially all of the Company’s intangible assets wererecognized as a consequence of the Company’s adoption offresh-start reporting. Such intangible assets include existingcontracts, order backlog and the value of various existingtechnologies used in the Company’s operations. Otherintangible assets are stated at cost less accumulatedamortization and impairment charges. The cost of otherintangible assets is reduced by the amounts related to reductionof deferred tax asset valuation allowances established atfresh-start accounting. (For a further description, see“Income Taxes” below and Note 21.) Amortizationis calculated on a straight-line basis over the estimated periodof benefit, ranging from one to 10 years.***Other Long-Lived Assets.***     Other long-lived assets consist of costs related to enteringinto long-term loan facilities (deferred debt issue costs),long-term receivables and fresh-start favorable contracts. TheCompany capitalizes debt issue costs relating to long-term debt,and such costs are charged to interest expense using theeffective interest method over the period the associated debt isoutstanding. Other long-term receivable includes accountsreceivable expected to be collected more than twelve monthsafter the balance sheet date including government grants andcontractual receivables related to asset removal obligations.***Impairment of Multi-Client Library.***     The Company evaluates the recoverability of its multi-clientlibrary in accordance with Statement of Financial AccountingStandards No. 144, *“Accounting for the Impairmentor Disposal of Long-Lived Assets”(“SFAS 144”)*, whenever events or changes incircumstances indicate that the carrying amounts may not be
F-13

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**recoverable. The level of estimated future sales for eachsurvey, as well as industry conditions, are key factors indetermining when seismic data should be evaluated forimpairment. Impairments are evaluated at least annually andwhenever there are specific indicators. In accordance with thestandard, the impairment evaluation is based first on acomparison of the undiscounted future cash flows over eachsurvey’s remaining estimated useful life with the carryingvalue of that survey. If the undiscounted cash flows are equalto or greater than the carrying value of the survey, noimpairment is recorded. If the undiscounted cash flows are lessthan the carrying value of the survey, the difference betweenthe carrying value of the survey and the discounted future valueof the expected revenue stream is recorded as an impairmentcharge.     The estimation of future cash flows and fair value is highlysubjective and inherently imprecise. Estimates can changematerially from period to period based on many factors includinghistorical and recent revenue trends, oil and gas prospects inparticular regions, general economic conditions affecting theCompany’s customer base, expected changes in technology andother factors that are deemed relevant.***Impairment of Long-Lived Assets (excluding Multi-Client    Library).***     Long-lived assets, which consist primarily of property, plantand equipment and oil and gas assets (or the group of assets,including the asset in question, that represents the lowestlevel of separately identifiable cash flows), are assessed forpossible impairment when indications of impairments exist inaccordance with SFAS 144. If the total of the undiscountedfuture cash flows is less than the carrying amount of the assetor group of assets, the asset is not recoverable and animpairment loss is recognized for the difference between theestimated fair value and the carrying value of the asset orgroups of assets. Other long-lived assets (property andequipment and oil and natural gas assets accounted for under thesuccessful efforts method) are also assessed for possibleimpairment upon the occurrence of a triggering event. Eventsthat can trigger assessments for possible impairments include,but are not limited to (i) significant decreases in themarket value of an asset, (ii) significant changes in theextent or manner of use of an asset, (iii) a physicalchange in the asset, (iv) a reduction of proved oil andnatural gas reserves based on field performance and (v) asignificant decrease in the price of oil or natural gas.***Steaming and Mobilization.***     Subsequent to the adoption of fresh-start reporting, costsincurred while relocating or “steaming” a vessel orcrew from one location to another are expensed as incurred.Onsite project costs such as positioning, deploying andretrieval of equipment at the beginning and end of a project areconsidered mobilization or demobilization costs and are includedin the cost of the multi-client survey or exclusive contractwith which the costs are associated. Prior to fresh-start, thePredecessor capitalized a proportionate share of cost incurredwhile relocating or “steaming” a seismic vessel orcrew as part of the cost of multi-client surveys.***Derivative Financial Instruments.***     The Company accounts for derivative financial instruments inaccordance with SFAS No. 133, *“Accounting forDerivative Instruments and Hedging Activities”(“SFAS 133”).* The Company uses derivativefinancial instruments to reduce risk exposure related tofluctuations in foreign currency rates and interest rates.Derivative instruments are recognized in the consolidatedbalance sheets at their fair values while realized andunrealized gains and losses attributable to derivativeinstruments that do not qualify for hedge accounting arerecognized and reported within other financial items, net, inthe consolidated statements of operations as they arise.     The Company applies either fair value or cash flow hedgeaccounting when a transaction meets the specified criteria inSFAS 133 to obtain hedge accounting treatment. To qualifyfor hedge accounting the instrument should be designated as ahedge at inception. At the time a financial instrument isdesignated as a hedge, the Company documents the relationshipbetween the hedging instrument and the hedged item.
F-14

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**Documentation includes risk management objectives and strategyin undertaking the hedge transaction, together with the methodsthat will be used to assess the effectiveness of the hedgingrelationship. Accordingly, the Company formally assesses, bothat the inception of the hedge and on an ongoing basis, whetherthe hedging derivatives have been “highly effective”in offsetting changes in the fair value or cash flows of thehedged item. A hedge is normally regarded as “highlyeffective” if, at inception and throughout its life, it canbe expected, and actual results indicate, that changes in thefair value or cash flows of the hedged item are effectivelyoffset by the changes in the fair value or cash flows of thehedging instrument. Actual results must be within a range of 80%to 125%. Hedge accounting will be discontinued when (a) itis determined that a derivative is not, or has ceased to be,highly effective as a hedge, (b) the derivative expires, oris sold, terminated or exercised, (c) when the hedged itemmatures or is sold or repaid, or (d) a forecast transactionis no longer deemed highly probable.     The Company applies hedge accounting for its interest ratehedging activities. At December 31, 2005, for a portion ofits floating rate debt, the Company has entered into interestrate swaps to effectively change the floating interest rates tofixed interest rates. The Company does not apply hedgeaccounting for its currency hedging activities (seeNote 19).***Revenue Recognition.***     The Company recognizes revenue when persuasive evidence of asale arrangement exists, delivery has occurred or services havebeen rendered, the sales price is fixed or determinable andcollection is reasonably assured. The Company defers theunearned component of payments received from customers for whichthe revenue recognition requirements have not been met. Forcontracts after July 1, 2003, the provisions ofEITF 00-21,*Revenue Arrangement with Multiple Deliverables*apply. Asa result, consideration is allocated among the separate units ofaccounting based on their relative fair values. TheCompany’s revenue recognition policy is described in moredetail below.***     Revenue Services.****1.     Geophysical Services (Marine,    Onshore and Other).*    (a) Sales of Multi-Client Library Data.     *Late sales* — The Company grants a license to acustomer, which entitles the customer to have access to aspecifically defined portion of the multi-client data library.The customer’s license payment is fixed and determinableand typically is required at the time that the license isgranted. The Company recognizes revenue for late sales when thecustomer executes a valid license agreement and has access tothe licensed portion of the multi-client library and collectionis reasonably assured.     *Volume sales agreements* — The Company grantslicenses to customers for access to a specified number of blocksof multi-client library within a defined geographical area.These licenses typically enable the customer to select andaccess the specific blocks over a period of time. Although thelicense fee is fixed and determinable in all cases, the paymentterms of individual volume sales agreements vary, ranging frompayment of the entire fee at the commencement of the volumesales agreement, to installment payments over a multi-yearperiod, to payment of the license fee as the specific blocks areselected.     Revenue recognition for volume sales agreements is based on aproportion of the total volume sales agreement revenue, measuredas the customer executes a license for specific blocks and hasbeen granted access to the data and collection is reasonablyassured.     *Pre-funding arrangements* — The Company obtainsfunding from a limited number of customers before a seismicacquisition project commences. In return for the pre-funding,the customer typically gains the ability
F-15

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**to direct or influence the project specifications, to accessdata as it is being acquired and to pay discounted prices.     Pre-funding revenue is recognized as the services are performedon a proportional performance basis. Progress is measured in amanner generally consistent with the physical progress on theproject, and revenue is recognized based on the ratio of theproject’s progress to date to the total project revenues,provided that all other revenue recognition criteria aresatisfied.    (b) Proprietary Sales/ Contract Sales.     The Company performs seismic services for a specific customer,in which case the seismic data is the exclusive property of thatcustomer. The Company recognizes proprietary/contract revenue asthe services are performed and become chargeable to the customeron a proportionate performance basis over the term of eachcontract. Progress is measured in a manner generally consistentwith the physical progress of the project, and revenue isrecognized based on the ratio of the project’s progress todate to the total project revenues, provided that all otherrevenue recognition criteria are satisfied.    (c) Other Geophysical Services.     Revenue from other geophysical services is recognized as theservices are performed, provided all other recognition criteriaare satisfied.*     2.**Production Services.*     Tariff-based revenue from Production services from operation ofFPSO vessels is recognized as production occurs, while day-raterevenue is recognized over the passage of time, provided allother recognition criteria are satisfied.*     3.**Revenue Products (Pertra).*     Revenue from production and sale of oil produced underproduction licenses is recognized as produced barrels are liftedand ownership passes to the customer, provided all otherrecognition criteria are satisfied.     Deferred costs associated with a revenue contract are limited tothe amount of deferred revenue related to the contract.     Reimbursements received for expenses incurred under a contractare characterized as revenue in accordance withEITF 01-14*“Income Statement Characterization of ReimbursementsReceived for‘Out-of-Pocket’Expenses Incurred”.****Income Taxes.***     Deferred tax assets and liabilities are recognized for theexpected future tax consequences of transactions and events.Under this method, deferred tax assets and liabilities aredetermined based on the difference between the financialstatement and tax bases of assets and liabilities using enactedtax rates in effect for the year in which the differences areexpected to reverse. Deferred tax assets are reduced by avaluation allowance to record the deferred tax assets at anamount expected to be more likely than not recoverable. Deferredtax assets and liabilities are adjusted for the effects ofchanges in tax laws and rates on the date of enactment. Inaccordance with Accounting Principles Board Opinion No. 23,*“Accounting for Income Taxes — SpecialAreas,”* the Company does not recognize any deferred taxliability on unremitted earnings of foreign subsidiaries whenremittance is indefinite.
F-16

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     When the Company adopted fresh start reporting, effectiveNovember 1, 2003, the Company established valuationallowances for deferred tax assets. As and when such deferredtax assets, for which a valuation allowance is established, arerealized or recognized in subsequent periods, the tax benefit isrecorded as a ratable reduction of the carrying value of alllong-term intangible assets existing at adoption of fresh-startaccounting until the value of such assets is reduced to zero.Any recognition of fresh-start deferred tax assets afterintangible assets are reduced to zero will be credited toshareholders’ equity.     Accounting standards are not specific on the ordering ofrecording a reversal of the fresh-start valuation allowance as areduction to intangibles and other adjustments to intangiblebalances. As a result, the Company had adopted the followingaccounting policy. At year end, effects of minimum amortizationon the multi-client library are recorded prior to impairment andreversal of fresh-start valuation allowance (see Note 21).Impairments that occur prior to year end (the event leading tothe impairment occurred prior to December 31, 2005) arerecorded before the reversal of fresh-start valuation allowance.The reversal of the fresh-start valuation allowance as areduction in the multi-client library is recorded prior tocompleting the annual impairment test to evaluate whether thecarrying value of the multi-client library is recoverable.***Asset Retirement Obligations.***     The Company implemented FASB Interpretation No. 47*“Accounting for Conditional Asset RetirementObligations” (“FIN 47”)*as ofDecember 31, 2005. FIN 47 is an interpretation ofSFAS 143 *“Accounting for Asset RetirementObligations”*, which refers to legal obligations toperform asset retirement activities. FIN 47 requires anentity to recognize a liability for the fair value of aconditional asset retirement obligation if the fair value of theliability can be reasonably estimated, even if timing and/ormethod of settlement is conditional on a future event that maynot be within the control of the entity. The implementation ofFIN 47 had no quantitative effect on the Company.     In accordance with Statement of Financial Accounting StandardsNo. 143, *“Accounting for Asset RetirementObligations” (“SFAS 143”)*, the Companyrecords the fair value of an asset retirement obligation as aliability in the period when it is incurred (typically when theasset is installed at the production location). When theliability is recorded, the Company capitalizes the cost byincreasing the carrying amount of the related properties, plantand equipment. Over time, the liability is increased for thechange in its present value each period, and the capitalizedcost is depreciated over the useful life of the related asset.Also, revisions to a previously recorded asset retirementobligation may result from changes in the assumptions used toestimate the cash flows required to settle the asset retirementobligation. The effect of such changes is recorded as anadjustment to the related asset.***Commitments and Contingencies.***     The Company accrues for loss contingencies when it is probablethat a loss will result from a contingency and the amount of theloss can be reasonably estimated.***Fresh-Start Reporting.***     In connection with the adoption of fresh-start reportingeffective November 1, 2003, the Company adopted newaccounting policies for certain transactions and activities, asfurther described in the individual descriptions of thesepolicies below. The most significant of these are: •     The successful efforts method of accounting for oil and natural    gas exploration and development activities was adopted.  •     The Company made certain changes to cost capitalization and    amortization policies for the multi-client library, including an    increase in minimum amortization by reducing the maximum    amortization period from eight to five years after completion of    a survey. Further, expenditures incurred in
F-17

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     connection with yard stay and steaming of vessels are expensed    as incurred. Such expenses were previously recognized as part of    multi-client project costs.     In addition, the Company revised certain accounting estimates,including a reduction of depreciable lives of Ramform seismicacquisition vessels and FPSOs, other than the*Petrojarl I*, from 30 to 25 years.***Oil and Natural Gas Assets.***     This policy applies only to Pertra, which was sold March 1,2005 (see Note 24).     Following its adoption of fresh-start reporting, the Companyuses the successful efforts method of accounting for oil andnatural gas properties. Under this method, all costs ofacquiring unproved oil and natural gas properties and drillingand equipping exploratory wells are capitalized pendingdetermination of whether the properties have proved reserves. Ifan exploratory well is determined not to have commercialquantities of reserves, the drilling and equipment costs for thewell are expensed and classified as exploration costs at thattime. Such expenses aggregated $11.4 million for the yearended December 31, 2004, while there were no such costs forthe years ended December 31, 2005 and 2003. All developmentdrilling and equipment costs are capitalized. Capitalized costsof proved properties are amortized on a property-by-propertybasis using theunit-of-productionmethod whereby the ratio of annual production to beginning ofperiod proved oil and natural gas reserves is applied to theremaining net book value of such properties. Oil and natural gasreserve quantities represent estimates only, and there arenumerous uncertainties inherent in the estimation process.Actual future production may be materially different fromamounts estimated, and such differences could materially affectfuture amortization of proved properties. Geological andgeophysical costs are expensed as incurred and presented asexploration costs. Such costs aggregated $1.4 million and$4.9 million for the years ended December 31, 2005 and2004, respectively, while there were no such costs for the yearended December 31, 2003.     Long-lived assets to be held and used, including proved oil andnatural gas properties accounted for under the successfulefforts method of accounting, are assessed for impairmentwhenever events or circumstances indicate that the carryingvalue of those assets may not be recoverable. An impairment lossis indicated if the sum of the expected future cash flows,undiscounted, is less than the carrying amount of the assets. Inthis circumstance, an impairment loss is recognized for theamount by which the carrying amount of the asset exceeds theestimated fair value of the asset.     Unproved properties are periodically assessed for impairment anda loss is recognized at the time of impairment. Unproved oil andnatural gas properties that are individually significant areperiodically assessed for impairment by comparing their cost totheir estimated value on a project-by-project basis. Theremaining unproved oil and natural gas properties, if any, areaggregated and an overall impairment allowance is provided basedon historical experience.     Prior to its adoption of fresh-start reporting, the Company usedthe SEC full cost method of accounting for oil and natural gasproperties. Under this method, all costs associated with theacquisition, exploration and development of oil and natural gasproperties are capitalized. Such costs include leaseacquisition, geological, geophysical, drilling, equipment,interest and overhead. Capitalized overhead costs are limited tosalaries and benefits for employees directly involved in theacquisition, exploration and development of the properties aswell as other costs directly associated with such activities.Costs are accumulated on a country-by-country basis.     Under the full cost method, capitalized costs are amortizedusing theunit-of-productionmethod on a country-by-country basis. Unevaluated properties areexcluded from the amortization base. Costs associated withunevaluated properties are transferred into the amortizationbase at such time as the wells are completed, the properties aresold, or the costs have been impaired. Future development costsand dismantlement and abandonment costs are included in theamortizable cost base.
F-18

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     In accordance with the SEC guidelines for the full cost method,the cost bases of proved oil and natural gas properties arelimited, on a country-by-country basis, to the estimated futurenet cash flows from proved oil and natural gas reserves usingprices and other economic conditions in effect at the end of thereporting period, discounted at 10%, net of related taxes(ceiling test). If the capitalized cost of proved oil andnatural gas properties exceeds this limit, the excess is chargedto expense as additional depreciation and amortization.***New Accounting Standards.***     December 31, 2005, FASB Interpretation(FIN) No. 47 *“Accounting for Conditional AssetRetirement Obligations” (“FIN 47”)*became effective. FIN 47 is an interpretation ofSFAS 143 *“Accounting for Asset RetirementObligations”*, which refers to legal obligations toperform asset retirement activities. FIN 47 requires anentity to recognize a liability for the fair value of aconditional asset retirement obligation, if the fair value ofthe liability can be reasonably estimated, even if timing and/ormethod of settlement is conditional on a future event that maynot be within the control of the entity. The implementation ofFIN 47 did not have any impact on the Company’sfinancial position.     In May 2005, the FASB issued SFAS No. 154,*“Accounting Changes and Error Corrections”(“SFAS 154”)*, a replacement of AccountingPrinciples Board (“APB”) Opinion No. 20 and FASBStatement No. 3. SFAS 154 requires retrospectiveapplication to prior periods’ financial statements of avoluntary change in accounting principle unless it isimpracticable. APB Opinion No. 20, *“AccountingChanges,”*previously required that most voluntarychanges in accounting principle be recognized by including innet income of the period of the change the cumulative effect ofchanging to the new accounting principle. SFAS 154 willbecome effective for accounting changes and corrections oferrors made after January 1, 2006.     In December 2004, the FASB issued SFAS No. 153,*“Exchanges of Nonmonetary Assets”(“SFAS 153”)*, an amendment of APB OpinionNo. 29. SFAS 153 is based on the principle thatexchanges of nonmonetary assets should be measured based on thefair value of the assets exchanged. APB Opinion No. 29,*“Accounting for Nonmonetary Transactions”(“APB 29”)*provided an exception to its basicmeasurement principle (fair value) for exchanges of similarproductive assets. Under APB 29, an exchange of aproductive asset for a similar productive asset was based on therecorded amount of the asset relinquished. SFAS 153eliminates this exception and replaces it with an exception forexchanges of nonmonetary assets that do not have commercialsubstance. SFAS 153 became effective for the Company fornonmonetary asset exchanges occurring after July 1, 2005,and did not have any material impact on our consolidatedfinancial statements.     In December 2004, the FASB issued SFAS No. 123-R*“Share-Based Payment” (“FASB 123-R”)*,which requires companies to recognize in the income statementthe grant-date fair value of stock options and otherequity-based compensation issued to employees. The standardbecomes effective for the Company as of January 1, 2006.The Company has no outstanding options and is not currentlyissuing stock options that would cause the adoption ofSFAS 123-R to impact the Company’s financial position,cash flows or results of operations.**NOTE 3 —****2003 Financial Restructuring and Fresh-Start Reporting*****Background of Restructuring.***     The Company had approximately $1.1 billion of debt andother contractual obligations maturing during 2003, of which$930 million were bank and senior note obligations of PGSASA. Based on the Company’s existing business plan andforecast at that time, it became clear that the Company was overleveraged and that a comprehensive financial restructuring wascrucial to the long-term viability of the Company. As a result,on July 29, 2003, the Company filed a voluntary petitionfor protection under Chapter 11 of the United StatesBankruptcy Code. The filing was based on a financialrestructuring plan that was pre-approved by a majority
F-19

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**of banks and bondholders and a group of the Company’slargest shareholders. The Company emerged from Chapter 11on November 5, 2003.     The financial restructuring involved only the parent company anddid not involve operating subsidiaries, which continued fulloperations, leaving customers, lessors, vendors, employees andsubsidiary creditors unaffected.***Financial Restructuring.***     In accordance with the plan of reorganization,$2,140 million of the Company’s senior unsecured debtwas canceled and the associated creditors received the following: •     $746 million of unsecured 10% Senior Notes, due 2010;  •     $250 million of unsecured 8% Senior Notes, due 2006;  •     $4.8 million of an eight-year unsecured senior term loan    facility (which the Company fully repaid in May 2004);  •     91% of new ordinary shares of PGS as constituted immediately    post restructuring, with an immediate reduction of this    shareholding to 61% through a rights offering of 30% of the new    ordinary shares to the pre-restructuring shareholders for    $85 million, or $14.17 per share; and  •     $40.6 million of cash, of which $17.9 million was    distributed in December 2003 and $22.7 million in May 2004.     In accordance with the plan, the share capital outstandingimmediately prior to the effectiveness of the restructuring,consisting of 103,345,987 shares, par value NOK 5, wascancelled and 20,000,000 new ordinary shares, par valueNOK 30, were issued. The pre-restructuring shareholdersreceived 4%, or 800,000, of the new ordinary shares (one newshare per 129 old shares), and the right to acquire 30%, or6,000,000, of the new ordinary shares (1,500,000 of which werecommitted to shareholders underwriting the rights offering and4,500,000 of which were available to all pre-restructuringshareholders on a basis of one new share per 23 old shares), for$85 million ($14.17 per share) in the rights offering.     Owners of $144 million of trust preferred securitiesreceived 5%, or 1,000,000, of the new ordinary shares. Theprincipal amount of the Company’s interest bearing debt andcapital lease obligations immediately after the restructuringwas approximately $1,210 million, a reduction ofapproximately $1,283 million.***Reorganization Value.***     The Company adopted fresh-start reporting upon its emergencefrom Chapter 11 in accordance withSOP 90-7.Accordingly, all assets and liabilities were adjusted to reflecttheir reorganization value as of November 1, 2003, whichapproximates fair value at the date of reorganization. TheCompany engaged independent financial advisors to assist in thedetermination of its reorganization value as defined inSOP 90-7. In thedisclosure statement dated September 10, 2003 prepared inthe bankruptcy proceeding, the Company, together with financialadvisors, determined through various analyses a reorganizationvalue as an enterprise value in the range of $1.3 billionto $1.7 billion. On this basis the Company determined thatthe reorganization value for the Company as defined bySOP 90-7 should beclose to the mid-range of $1.5 billion.     These analyses are necessarily based on a variety of estimatesand assumptions which, though considered reasonable bymanagement, may not be realized and are inherently subject tosignificant business, economic and competitive uncertainties andcontingencies, many of which are beyond the Company’scontrol. These estimates and assumptions had a significanteffect on the determination of the reorganization value.Accordingly, there can be no assurance that the estimates,assumptions and values reflected in the valuations will berealized, and actual results could vary materially.
F-20

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)*****Fresh-Start Reporting.***     The consolidated balance sheets as of December 31, 2005 and2004 and the consolidated statements of operations and cashflows for the years ended December 31, 2005 and 2004, andthe two months ended December 31, 2003 are for theSuccessor and give effect to adjustments to the carrying valueof assets or amounts and classifications of liabilities thatwere necessary upon adoption of fresh-start reporting as ofNovember 1, 2003. The consolidated statements of operationsand cash flows for the ten months ended October 31, 2003are for the Predecessor and reflect the assets and liabilitiesof PGS on a historical cost basis including the effect atOctober 31, 2003 of the fresh-start adjustments. Theadoption of fresh-start reporting had a material effect on theconsolidated balance sheet as of December 31, 2004 and onthe consolidated statements of operations for the year endingDecember 31, 2004 and the two-month period endingDecember 31, 2003 and will have a material impact onconsolidated statements of operations for subsequent periods.Consequently, the financial information for the Successor andPredecessor companies are not comparable.     In connection with the adoption of fresh-start reporting onNovember 1, 2003, the Company also adopted new accountingpolicies for certain transactions and activities related to themulti-client library, steaming and mobilization costs, certainother property and equipment, and oil and natural gasexploration, development and production activities. All newaccounting policies under fresh-start reporting are described inNote 2.     The following table summarizes the adjustments required torecord the reorganization and the issuance of the varioussecurities in connection with the implementation of the plan ofreorganization:                                                   **Recovery**       **PGS ASA Plan of**   **Elimination**   **Term** **Common Stock** **Total Recovery****Reorganization** **Predecessor** **of Debt and** **Surviving**   **2010** **2006** **Loan**    **Recovery Analysis** **Company** **Equity** **Debt** **Cash** **Note** **Note** **Facility** **%** **Value** **%** **Value**                         **(In thousands of dollars, except percentages)**    Other liabilities — not affected $338,536  $—  $—  $—  $—  $—  $—      $—      $—     Unsecured Debt  2,140,000   (2,140,000)  —   40,592   745,949   250,000   4,810   91.0%  330,458   64%  1,371,809     Trust Preferred Securities (incl. accrued interest)  155,203   (155,203)  —   —   —   —   —   5.0%  18,157   12%  18,157     Capital lease obligations  89,913   —   89,913   —   —   —   —   —   —   100%  89,913     Senior Secured Debt  113,970   —   113,970   —   —   —   —   —   —   100%  113,970     Debt of Subsidiaries — not affected  5,295   —   5,295   —   —   —   —   —   —   100%  5,295     Common Stockholders  71,089   (71,089)  —   —   —   —   —   4.0%  14,526   20%  14,526     Deficit  (429,531)  429,531   —   —   —   —   —   —   —       —                                       Total $2,484,475  $(1,936,761) $209,178  $40,592  $745,949  $250,000  $4,810   100.0% $363,141   65% $1,613,670                                       Adjusted for fair value adjustment of interest rate variation on    UK leases                                         $51,642     Adjusted for cash                                          (148,912)                                      Reorganization value                                         $1,516,400                                        Fresh-start adjustments reflect the allocation of fair value tocurrent and long-lived assets and the present value ofliabilities to be paid as calculated with the assistance ofindependent third party valuation specialists. Current andlong-lived assets were valued based on a combination of thecost, income and market approach. Also considered was technical,functional and economic obsolescence.     In applying fresh-start reporting, the Company followed theseprinciples: •     The reorganization value of the Company was allocated to the    Company’s assets in conformity with the procedures    specified by Statement of Financial Accounting Standards    No. 141, *“Business*
F-21

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)** *Combinations.”* The sum of the amounts assigned to    assets and liabilities was within the range of the estimated    reorganization value and close to the mid-range of the    valuation. Therefore, there was no excess or deficit value to be    allocated to goodwill or long-term assets.  •     Each liability and contingency existing as of the fresh-start    reporting date, other than deferred taxes, has been stated at    the present value of the amounts to be paid, determined at    appropriate then current interest rates.  •     Deferred taxes were recorded in conformity with applicable    income tax accounting standards, principally Statement of    Financial Accounting Standards No. 109, *“Accounting    for Income Taxes”.* Deferred tax assets and liabilities    have been recognized for differences between the assigned values    and the tax basis of the recognized assets and liabilities (see    Note 21). Valuation allowances have been provided for    deferred tax assets.  •     Changes in existing accounting principles that otherwise would    have been required in the consolidated financial statements of    the emerging entity within the twelve months following the    adoption of fresh-start reporting were adopted at the time    fresh-start reporting was adopted.  •     Resetting the multi-client library, the property and equipment    and oil and natural gas assets to fair value and eliminating all    of the accumulated depreciation.**NOTE 4 —****Net Gain on Sale of Subsidiaries**     In March 2005, the Company sold its wholly owned subsidiaryPertra AS to Talisman Energy (UK) Ltd. and recognized again of $149.8 million, including $2.5 millionreceived to grant an option to make certain amendments to thecharter and operating agreement for the *Petrojarl Varg.*As part of the transaction, the Company is entitled to receiveadditional sales consideration equal to the value, on a postpetroleum tax basis, of 50% of the relevant revenues from theVarg field in excess of $240 million for each of the yearsended December 31, 2005 and 2006. In January 2006, theCompany received $8.1 million, representing the 2005portion of the contingent consideration, which amount wasaccrued in December 2005, resulting in an aggregate net gain onthe sale of Pertra AS of $157.9 million. See Note 24for additional information relating to the disposal of Pertra AS.     In August 2005, the Company entered into an agreement to sellits wholly owned subsidiary PGS Reservoir AS to ReservoirConsultants Holding AS (“RCH”), which is controlled bya group of former PGS employees. RCH has the option to sell theshares back to the Company for an amount equal to the saleconsideration, which option expires 12 months from thecompletion date (August 31, 2005). The Company has recordedan estimated loss of $1.5 million for this transaction. SeeNote 24 for additional information relating to theagreement.
F-22

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)****NOTE 5 — Impairment of Long-Lived Assets andOther Operating (Income) Expense, Net**     Impairments of long-lived assets consist of the following:                      **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Multi-client library (Note 10)(a) $—  $—  $—  $90,053     Production assets and equipment (Note 9)  —   —   —   328     Seismic assets and equipment (Note 9)  4,575   —   —   3,539     Other long-lived assets  —   —   —   1,091                   Total $4,575  $—  $—  $95,011                   (a)    The multi-client library impairment for the ten months ended    October 31, 2003 is comprised of $85.0 million in    Marine Geophysical and $5.1 million in Onshore.     During 2005 the Company decided to convert its 4C crew into astreamer operation, resulting in an impairment of$4.6 million. In 2003, the Company’s sales estimatesfor several of its multi-client surveys were revised downwardsignificantly, resulting in impairments of such surveys.     Other operating (income) expense, net consists of the following:                      **Predecessor**  **Successor Company** **Company**           **Ten**  **Years Ended** **Two Months** **Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Release of contingent liability re UK lease (Note 20) $(17,248) $—  $—  $—     Gain on claim re equipment  (8,847)  —   —   —     Cost of employees termination and reorganization  —   665  $582   19,235     Cost relating to completion of 2002 U.S. GAAP accounts and    re-audit of 2001  —   7,447   470   2,089                   Total $(26,095) $8,112  $1,052  $21,324              **NOTE 6 — Shares Available for Sale andInvestments in Securities**     Shares available for sale relates to the Company’sinvestment in Endeavour International Corp., which investmentwas originally acquired as consideration for the contribution oflicenses to use the Company’s seismic data in the NorthSea. The Company owns approximately 3.3% of Endeavour’sshares, which had an original cost of $3.8 million. Inadjusting the shares to fair value, an unrealized loss of$2.1 million has been recorded directly to othercomprehensive income for the year ended December 31, 2005.For the year ended December 31, 2004, the Company recordedan unrealized gain of $5.9 million. Fair value of theshares was $7.6 million and $9.7 million as ofDecember 31, 2005 and 2004, respectively.
F-23

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     The Company also has investments in securities with fair valuetotalling $5.6 million as of December 31, 2005 andrecorded an unrealized gain of $0.2 million for the yearended December 31, 2005 directly to other comprehensiveincome.**NOTE 7 — Accounts Receivable, Net**     Accounts receivable, net, consists of the following:            **December 31,**     **2005** **2004**       **(In thousands of dollars)**    Accounts receivable — trade $216,157  $162,775     Allowance for doubtful accounts  (2,536)  (1,492)            Total $213,621  $161,283             The change in allowance for doubtful accounts is as follows:                       **Predecessor**  **Successor Company** **Company**         **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Beginning balance $1,492  $3,444  $2,913  $4,648     New and additional allowances  2,067   1,001   837   2,615     Write-offs and reversals  (1,023)  (2,953)  (179)  (4,350)    Disposal of subsidiary  —   —   (127)  —                    Ending balance $2,536  $1,492  $3,444  $2,913                  Related to:                     Accounts receivable, net $2,536  $1,492  $3,115  $2,472      Unbilled and other receivables  —   —   329   314      Assets of discontinued operations  —   —   —   127                    Total $2,536  $1,492  $3,444  $2,913              
F-24

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)****NOTE 8 — Other Current Assets**     Other current assets consist of the following:            **December 31,**     **2005** **2004**       **(In thousands of**  **dollars)**    Prepaid operating expenses $20,965  $13,053     Spare parts, consumables and supplies  17,485   12,840     Withholding taxes and taxes receivable  13,588   15,821     Prepaid reinsurances  6,572   5,831     Assets of business transferred under a contractual arrangement    (Notes 4 and 24)  3,504   —     Produced oil, not lifted  —   5,037     Other  5,623   7,924             Total $67,737  $60,506        **NOTE 9 — Property and Equipment, Net**     The components of property and equipment, including property andequipment under capitalized leases, are summarized as follows:            **December 31,**     **2005** **2004**       **(In thousands of dollars)**    Seismic vessels and equipment $507,607  $435,622     Production vessels and equipment  675,062   680,737     Fixtures, furniture and fittings  27,378   18,383     Buildings and other  7,521   4,412           1,217,568   1,139,154     Accumulated depreciation and impairment  (245,550)  (130,146)            Total $972,018  $1,009,008             The net book value of property and equipment under UK leaseswere $588.8 million and $616.5 million atDecember 31, 2005 and 2004, respectively (see Note 20).     As seismic vessels and equipment are not separatecash-generating units, such assets are presented on a combinedbasis. Vessels and equipment subject to capital leases that arepart of a group are presented and evaluated on a combined basis.See Note 2 for a further description of the accountingpolicy for impairments of long-lived assets.     During 2005 the Company decided to convert its 4C crew into astreamer operation, resulting in an impairment of$4.6 million. Impairment charges were also recorded in theten months ended October 31, 2003 (see Note 5).
F-25

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     The following table summarizes depreciation expense:                     **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Depreciation expense, net of amounts capitalized into    multi-client library $106,707  $106,629  $18,206  $121,485     Depreciation expense capitalized into multi-client library  5,415   3,982   1,329   11,766 ***Subsequent Events.***     In January 2006 the Company entered into an agreement topurchase the shuttle tanker MT *Rita Knutsen*for$35 million from Knutsen OAS Shipping AS. The transactionwas completed on March 9, 2006. The Company considers thevessel to be a possible FPSO solution for several upcomingprojects, and the Company intends to begin a conversion when afirm contract for the ship is secured. The vessel will beoperated by Knutsen OAS Shipping AS under a bareboat charteragreement until a decision to start conversion is made.     In March 2006, the Company announced that it intends to build anew third generation Ramform seismic vessel at Aker Yards,Langsten, Norway. The Company expects the new Ramform classseismic vessel to cost approximately $85 million from theyard including installation, but excluding the cost of seismicequipment. The new Ramform is expected to be delivered in thefirst quarter of 2008.**NOTE 10 — Multi-Client Library, Net**     The net carrying value of the multi-client library, by the yearin which the components were completed, is summarized as follows:            **December 31,**     **2005** **2004**       **(In thousands of dollars)****Completed surveys:**            Completed during 1999, and prior years $6,251  $26,772     Completed during 2000  5,881   21,976     Completed during 2001  66,626   106,876     Completed during 2002  18,785   35,393     Completed during 2003  14,859   33,296     Completed during 2004  4,347   11,620     Completed during 2005  7,746   —             Completed surveys  124,495   235,933     Surveys in progress  21,676   8,756            Multi-client library $146,171  $244,689        
F-26

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     The following table summarizes multi-client library impairmentcharges, amortization expense, capitalization of interest anddepreciation and amounts credited to the multi-client libraryrelated to reduction of deferred tax asset valuation allowancesestablished at fresh-start accounting:                     **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Impairment charges (Note 5) $—  $—  $—  $90,053     Amortization expense  134,469   208,468   33,347   148,399     Interest capitalized into multi-client library  1,878   1,461   375   2,083     Depreciation capitalized into multi-client library  5,415   3,982   1,329   11,766     Reduction of deferred tax asset valuation allowance    (Note 21)  25,312   —   —   —      Amortization expense for the year ended December 31, 2005includes $35.4 million of additional non-sales relatedamortization. This amount includes $20.4 million in minimumamortization and $15.0 million of non-sales relatedamortization (impairment) to reflect reduced fair value offuture sales on certain individual surveys ($14.4 millionin Marine Geophysical and $0.6 million in Onshore). For theyear ended December 31, 2004 the additional non-salesrelated amortization totaled $48.8 million of which$28.9 million was for minimum amortization and$19.9 million for non-sales related amortization(impairment) ($18.8 million in Marine Geophysical and$1.1 million in Onshore). For the two months endedDecember 31, 2003 and the ten months ended October 31,2003, the Company recognized $0.0 million and$36.6 million, respectively, in minimum amortization.     For informational purposes, the following shows the hypotheticalapplication of the Company’s minimum amortizationrequirements to the components of the existing multi-clientlibrary. These minimum amortization requirements are calculatedas if there will be no future sales of these components or anyadditional effect of reduction in deferred tax asset valuationallowances credited to the multi-client library.        **Minimum Future**  **Amortizations**     **(In thousands of**  **dollars)**    During 2006 $33,680     During 2007  43,816     During 2008  43,975     During 2009  9,779     During 2010  7,814     During 2011  7,107          Future minimum amortization $146,171          Because the minimum amortization requirements generally apply tothe multi-client library on a survey-by-survey basis rather thanin the aggregate, the Company may incur significant minimumamortization charges in a given year even if the aggregateamount of ordinary amortization charges recognized exceeds theaggregate minimum amortization charges above.
F-27

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     At the Company’s adoption of fresh-start reporting,effective November 1, 2003, the Company establishedvaluation allowances for deferred tax assets. If such deferredtax assets, for which a valuation allowance is established, arerealized or recognized in subsequent periods, the reversal ofvaluation allowance will be recorded as a ratable reduction ofthe carrying value of all long-term intangible assets andcertain favorable lease contracts existing at adoption offresh-start accounting until the value of such assets is reducedto zero. At December 31, 2005, the Company recorded a$25.3 million reduction of the carrying amounts of themulti-client library due to such a reversal of valuationallowance, which is reflected in the table above as a reductionin gross costs (see Note 21).**NOTE 11 — Other Intangible Assets, Net**     The components of other intangible assets, net, are summarizedas follows:            **December 31,**     **2005** **2004**       **(In thousands of dollars)**    Existing technology $29,329  $30,548     Existing contracts  16,643   16,772     Order backlog  5,401   5,401     Patents, royalties and licenses  1,687   659             Total cost  53,060   53,380     Accumulated amortization  (28,674)  (17,266)            Total $24,386  $36,114             Other intangible assets existing at December 31, 2005 and2004 were primarily recognized in conjunction with the adoptionof fresh-start reporting, effective November 1, 2003. Thefollowing table summarizes amortization expense amounts creditedto the other intangible assets related to reduction of deferredtax asset valuation allowances established at fresh-startaccounting:                     **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Amortization expense $11,458  $13,778  $3,488  $1,480     Reduction of deferred tax asset valuation allowance    (Note 21)  1,348   3,291   —   —      The weighted average remaining amortization period for otherintangible assets as of December 31, 2005 is6.3 years, and the amortization expense related to theseassets under existing amortization plans is $5.9 million(2006), $4.1 million (2007), $3.7 million (2008),$2.2 million (2009) and $8.5 million (2010 andthereafter). These amortizations are calculated as if there willbe no additional effect of reduction in deferred tax assetvaluation allowances credited to the other intangible assets.     As described in Note 10, the reduction of the valuationallowance for deferred tax assets established in fresh-startaccounting results in a reduction of certain intangible assets.At December 31, 2005 and 2004, the Company recorded$1.3 million and $3.3 million, respectively, inreduction of the carrying amounts of other intangible assets dueto reversal of valuation allowance (see Note 21).
F-28

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)****NOTE 12 — Other Long-Lived Assets**     Other long-lived assets consist of the following:            **December 31,**     **2005** **2004**       **(In thousands of**  **dollars)**    Long-term receivables $16,893  $14,945     Governmental grants and contractual receivables  5,577   17,204     Favorable lease contracts  7,829   10,444     Deferred debt issue costs  9,787   2,066             Total $40,086  $44,659             Governmental grants and contractual receivables relate to grantsfrom the Norwegian Government and contractual payments from FPSOcontract counterparties that the Company is entitled to receiveto cover parts of its asset retirement obligations (seeNotes 2 and 14).     The fair value of certain favorable lease contracts totaling$14.2 million were recognized in the Company’s balancesheet in connection with the adoption of fresh-start reporting,effective November 1, 2003. The amortization of thesecontracts over the remaining lease periods (which averageapproximately 4 years) is recorded as an increase of leaseexpense as part of cost of sales. The Company recorded$2.1 million, $2.4 million and $0.4 million ofsuch increase in lease expense for the years endedDecember 31, 2005 and 2004 and the two months endedDecember 31, 2003, respectively.     As described in Note 10, the reduction of the valuationallowance for deferred tax assets established in fresh-startaccounting results in a reduction of certain intangible assets.At December 31, 2005 and 2004, the Company recorded$0.5 million and $1.0 million, respectively, inreduction of the carrying amounts of favorable lease contractsdue to reversal of valuation allowance (see Note 21).**NOTE 13 — Accrued Expenses**     Accrued expenses consist of the following:            **December 31,**     **2005** **2004**       **(In thousands of**  **dollars)**    Accrued employee payroll $44,864  $37,659     Accrued vessel operating expenses  30,074   17,080     Customer advances and deferred revenue  29,723   12,070     Forward exchange contracts (Note 19)  7,234   —     Received, not invoiced, property and equipment  7,967   5,618     Accrued commissions  7,550   9,683     Accrued interest expenses  5,778   3,394     Liabilities of business transferred under a contractual    arrangement (Notes 4 and 24)  3,504   —     Accrued severance  27   290     Other  27,606   29,462             Total $164,327  $115,256        
F-29

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Changes in accrued severance and restructuring costs are asfollows:                      **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Beginning balance $290  $5,061  $8,367  $1,215     Additional and adjustment of allowances  (40)  (632)  1,764   18,469     Severance and restructuring costs paid  (223)  (4,139)  (5,070)  (11,317)                  Ending balance $27  $290  $5,061  $8,367              **NOTE 14 — Other Long-Term Liabilities**     Other long-term liabilities consist of the following:            **December 31,**     **2005** **2004**       **(In thousands of dollars)**    Accrued liabilities UK leases (Note 20) $50,765  $79,344     Pension liability (Note 22)  45,443   52,472     Asset retirement obligations (“ARO”) (Note 2)  20,015   58,518     Tax contingencies  19,184   25,522     Interest rate swaps (Note 19)  1,628   —     Other  3,755   3,794             Total $140,790  $219,650             The following table presents changes in asset retirementobligations for the years ending December 31, 2005 and2004, the two months ended December 31, 2003 and the tenmonths ended October 31, 2003:                     **Predecessor**  **Successor Company** **Company**         **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Balance at beginning of period $58,518  $50,016  $49,847  $59,767     Accretion expense  1,426   4,005   599   3,793     Liabilities settled in the period  (15)  —   (430)  —     Disposal of subsidiary (Pertra AS)  (39,914)  —   —   —     Revision in estimated cash flow/fair value  —   4,497   —   (13,713)                 Balance at end of period $20,015  $58,518  $50,016  $49,847                   The ARO liability as of December 31, 2005 relates mainly tothe Banff field and will be settled at the end of the contract,currently expected to be no later than 2014.     As of December 31, 2005, the Company had asset retirementobligations for the sub-sea production facility associated with*Ramform Banff* FPSO operating in the North Sea. Theseobligations generally relate to restoration of the environmentsurrounding the facility and removal and disposal of all theproduction equipment. The asset retirement obligation will becovered in part by contractual payments from FPSO
F-30

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**contract counterparties (see Note 12). The receivable hasbeen included in the consolidated balance sheets under otherlong-lived assets.**NOTE 15 — Short-Term Debt and Current Portionof Long-Term Debt**     Short-term debt and current portion of long-term debt consist ofthe following:            **December 31,**     **2005** **2004**       **(In thousands of**  **dollars)**    Short-term debt (see Note 16) $2,674  $1,962     Current portion of long-term debt (see Note 16)  21,732   17,828             Total $24,406  $19,790        **NOTE 16 — Debt*****Long-Term Debt.***     Long-term debt consists of the following:            **December 31,**     **2005** **2004**       **(In thousands of dollars)****Unsecured:**             10% Senior Notes, due 2010 $4,624  $745,949      8% Senior Notes, due 2006  —   250,000 **Secured:**             Term loan, due 2012, Libor + margin (see below)  850,000   —      8.28% First Preferred Mortgage Notes, due 2011  87,930   98,920      Other loans, due 2006  1,312   8,149             Total debt  943,866   1,103,018     Less current portion  (21,732)  (17,828)            Total long-term debt $922,134  $1,085,190             Aggregate maturities of long-term debt as of December 31,2005 are as follows:        **December 31,**  **2005**     **(In thousands**  **of dollars)**    Year of repayment:        2006 $21,732     2007  21,400     2008  22,540     2009  23,660     2010  29,554     Thereafter  824,980          Total $943,866     
F-31

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     In December 2005, the Company entered into a new creditagreement, establishing a term loan of $850 million(“Term Loan”) and a revolving credit facility(“RCF”) of $150 million (see below). The TermLoan amortizes 1% per annum, with the remaining balance duein 2012, and bears interest at a rate of LIBOR plus a marginthat depends on our leverage ratio. Leverage ratio, as definedin the Credit Agreement, is the ratio of consolidatedIndebtedness to Consolidated EBITDA reduced by multi-clientinvestments made for the period in question. At a leverage ratioof 2.25:1 or greater, the applicable margin will be2.5% per annum. Below that level, the margin will be2.25% per annum. The credit agreement generally requiresthe Company to apply 50% of excess cash flow to repayoutstanding borrowings for periods when our leverage ratioexceeds 2:1. Excess cash flow for any period is defined as netcash flow provided by operating activities during that periodless capital expenditures made in that period or committed to bemade in the next period, less debt service payments and lessaccrued income taxes to be paid in the next period. The Companycan make optional payments to reduce the principal at nopenalty. The Term Loan is an obligation of PGS ASA and PGSFinance Inc. as co-borrowers, is secured by pledges of shares ofcertain material subsidiaries and is guaranteed by certainmaterial subsidiaries.     The Company has hedged the interest rate on 50% of theborrowings under the Term Loan by entering into interest rateswaps where the Company receives floating interest rate based on3 months LIBOR and pays fixed interest rate payments basedon LIBOR for 3 and 5 year maturities. See Note 19 forfurther information.     The 10% Senior Notes due 2010 (“10% Notes”)bear interest at 10% per annum payable semi-annually andmature in November 2010 with no required principal paymentsuntil maturity. The 10% Notes are callable by the Companybeginning in November 2007 and are callable thereafter at parplus a premium of 5% declining linearly until maturity. InDecember 2005, the Company refinanced and retired$741.3 million of the 10% Notes. The 10% Notesare unsecured obligations of PGS ASA.     The 8.28% First Preferred Mortgage Notes due 2011(“8.28% Notes”) bear interest at 8.28% perannum, and interest and scheduled principal amounts are payablesemi-annually. The 8.28% Notes are subject to redemption atpar on a pro rata basis through operation of a mandatory sinkingfund on a semi-annual basis according to a schedule and aresubject to optional redemption by the Company beginning in June2006 at a redemption price equal to 100% of the principal amountplus a make whole premium that is based on U.S. treasuryrates plus 0.375%. The 8.28% Notes are secured by, amongother things, a mortgage on the *Ramform Explorer* and the*Ramform Challenger*seismic vessels. In addition, there isestablished under the indenture for the 8.28% Notes a debtservice reserve fund, which was initially funded in an amount(approximately $10 million) equal to the maximum interestand sinking fund payment due on the 8.28% Notes on anypayment date for such notes through December 1, 2010. Suchadditional amount has been invested in a funding agreement thatserves as a source of funds that, together with charter hirepayments made by a Company subsidiary under charters for the*Ramform Explorer*and the *Ramform Challenger*vessels, are used to make debt service payments on the8.28% Notes. This debt service reserve fund investment ispresented as long-term restricted cash in the consolidatedbalance sheets because funds derived from the investment will beused to make final debt service payments on the 8.28% Notes.***Bank Credit Facilities.***     In December 2005, the Company replaced its secured$110 million revolving credit facility, originally maturingin 2006, with a new revolving credit facility (“RCF”)of $150 million. The new RCF is part of the same creditagreement as the $850 million Term Loan described above andmatures in 2010. The Company may use up to $60 million ofcapacity under the RCF for letters of credit and may borrowU.S. dollars, or any other currency freely available in theLondon banking market to which the lenders have given priorconsent, under the RCF for working capital and for generalcorporate purposes. The Company may use these letters of credit,which can be obtained in various currencies, to secure, amongother things, performance and bid bonds required in our ongoingbusiness. Borrowings under the RCF bear interest at a rate equalto LIBOR plus a
F-32

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**margin that depends on our leverage ratio. At a leverage ratioof 2.25:1 or greater, the applicable margin will be 2.25%; at aleverage ratio between 2:1 and 2.25:1, the applicable marginwill be 2.00%; and at a leverage ratio below 2:1, the applicablemargin will be 1.75. At December 31, 2005,$14.6 million of letters of credit were issued under theRCF and the applicable margin was 2.25% per annum. Inaddition, the Company may be able to borrow an additional$250 million that would be secured by the same collateralthat secures the Term Loan and borrowings under the RCF.***Short-Term Debt.***     Net short-term debt was $2.7 million as ofDecember 31, 2005, relating to our Onshore business. As ofDecember 31, 2004, net short-term debt was$2.0 million, of which $1.8 million related to thepurchase of the seismic vessel *Falcon Explorer.****Covenants.***     Our December 2005 credit facility contains financial covenantsand negative covenants that restrict us in various ways. Thefacility provides that •     our total leverage ratio may not exceed 3.50 to 1.0 in 2006,    3.25 to 1.0 in 2007 and 3.00 to 1.0 in 2008, and may not exceed    3.00 to 1.0 at the time of our proposed separation transaction    described under “Information on the Company  —    Proposed Separation of the Geophysical and Production    Businesses” in Item 4 of this annual report,  •     our consolidated interest coverage ratio (defined as the ratio    of consolidated EBITDA less multi-client investments to    consolidated interest expense) must be at least 3.0 to 1.0, and  •     our consolidated fixed charge coverage ratio (defined as the    ratio of consolidated EBITDA less multi-client investments to    consolidated fixed charges) must be at least 1.3 to 1.0.     In addition, the credit agreement restricts our ability, amongother things, to sell assets; incur additional indebtedness orissue preferred stock; prepay interest and principal on ourother indebtedness; pay dividends and distributions orrepurchase our capital stock; create liens on assets; makeinvestments, loans, guarantees or advances; make acquisitions;engage in mergers or consolidations; enter into sale andleaseback transactions; engage in transactions with affiliates;amend material agreements governing our indebtedness; change ourbusiness; enter into agreements that restrict dividends fromsubsidiaries; and enter into speculative financial derivativeagreements.     The Company is in compliance with the covenants in its loan andlease agreements as of December 31, 2005.***Pledged Assets.***     Certain seismic vessels and seismic equipment with a net bookvalue of $45.4 million and $55.2 million atDecember 31, 2005 and 2004, respectively, are pledged assecurity under the Company’s short-term and long-term debt.In addition, under the credit agreement established in December2005, certain shares in material subsidiaries have been pledgedas security.***Letter of Credit and Guarantees.***     The Company had aggregate outstanding letters of credit andrelated types of guarantees, not reflected in the accompanyingconsolidated financial statements, of $32.7 million(including $14.6 million described above) and$30.1 million at December 31, 2005 and 2004,respectively.
F-33

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)****NOTE 17 — Interest Expense**     Interest expense consists of the following:                      **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Interest expense, gross $(98,234) $(112,272) $(17,245) $(92,504)    Interest on trust preferred securities  —   —   —   (8,536)    Interest capitalized in multi-client library (Note 10)  1,878   1,461   375   2,083                   Total interest expense $(96,356) $(110,811) $(16,870) $(98,957)             **NOTE 18 — Other Financial Items, Net**     Other financial items, net, consist of the following:                      **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Interest income $7,442  $4,840  $1,050  $4,467     Foreign currency gain (loss)  4,098   (8,024)  (5,208)  (4,286)    Sale of shares in Aqua Exploration Ltd.   —   1,500   —   —     Other  (5,622)  (9,177)  (106)  (1,653)                  Total other financial items, net $5,918  $(10,861) $(4,264) $(1,472)                  Other includes additional required rental payments relating toUK leases of $7.2 million for each of the years endedDecember 31, 2005 and 2004, $4.9 million for the twomonths ended December 31, 2003 and $1.5 million forthe ten months ended October 31, 2003 (see Note 20).**NOTE 19 — Financial Instruments*****Fair Values of Financial Instruments.***     The carrying amounts of cash and cash equivalents, restrictedcash, accounts receivable, unbilled and other receivables, othercurrent assets, accounts payable and accrued expensesapproximate their respective
F-34

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**fair values because of the short maturities of thoseinstruments. The carrying amounts and the estimated fair valuesof debt instruments are summarized as follows:                            **December 31, 2005** **December 31, 2004**       **Carrying** **Notional** **Fair** **Carrying** **Notional**    **Amounts** **Amounts** **Values** **Amounts** **Amounts** **Fair Values**               **(In thousands of dollars)**    Long-term debt (Note 16) $943,866  $—  $947,105  $1,103,018  $—  $1,218,386     Derivatives:                             Forward exchange contracts (Note 13)  (7,234)  193,536   (7,234)  —   —   —      Interest rate swaps (cash flow hedging instruments)    (Note 14)  (1,628)  425,000   (1,628)  —   —   —      Commodity derivatives  —   —   —   (2,583)  —   (2,583)     The fair values of the long-term debt instruments, forwardexchange contracts and interest rate swaps are estimated usingquotes obtained from dealers in such financial instruments orlatest quoted prices at Bloomberg.     There is established under the indenture for the8.28% Notes a debt service reserve fund, which wasinitially funded in an amount (approximately $10 million)equal to the maximum interest and sinking fund payment due onthe 8.28% Notes on any payment date for such notes throughDecember 1, 2010. Such additional amount has been investedin a funding agreement that serves as a source of funds that,together with charter hire payments made by a Company subsidiaryunder charters for the *Ramform Explorer* and the*Ramform Challenger*vessels, are used to make debt servicepayments on the 8.28% Notes. The amounts held in or payableinto the debt service reserve fund will be used as part of thefinal payments on the 8.28% Notes. The Company classifiesthis amount as restricted cash (long-term) in its consolidatedbalance sheets ($10 million).***Interest Rate Exposure.***     The Company holds interest rate derivative instruments. As ofDecember 31, 2005, the Company had outstanding interestrate swap agreements in the aggregate notional amount of$433.6 million, of which $8.6 million either maturedin January 2006 or were terminated in February 2006. As ofDecember 31, 2005, we had entered into interest rate swapsrelating to $425 million of the $850 million Term Loanand changed our interest rate exposure from floating to fixedinterest rates for the $425 million notional amount. Weaccount for these swaps as interest rate hedges. Under theseinterest rate swap agreements, the Company receives floatinginterest rate payments based on 3 month LIBOR and paysfixed interest rate payments. As to a notional amount of$150 million, a fixed rate of 4.84% will apply throughDecember 2008. As to a notional amount of $275 million, anaverage fixed rate of 4.88% will apply through December 2010.The aggregate negative fair value of these interest rate swapagreements at December 31, 2005 was approximately$1.6 million and is reported as other long-termliabilities. The same amount, in accordance with SFAS 133,is recorded as a reduction in other comprehensive income as theeffective portion of the designated and qualifying hedginginstrument (the interest swaps).***Foreign Exchange Exposure.***     The Company is exposed to currency fluctuation due to apredominantly USD-based revenue stream, while the Company’sexpenses are incurred in various currencies. The larger expensecurrencies other than the
F-35

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**USD are GBP and NOK. In 2005, the Company adopted a foreigncurrency hedging program by buying NOK and GBP on forwardcontracts. As of December 31, 2005, the Company had openforward contracts to buy GBP and NOK amounting to approximately$193.5 million with a negative fair value of$7.2 million reported as accrued expenses. As ofDecember 31, 2004, the Company did not have any openforward exchange contracts. The currency forward contracts arenot accounted for as hedges.***Commodity Derivatives.***     Through February 2005, the Company operated in the worldwidecrude oil market through its subsidiary Pertra AS, which wassold March 1, 2005 (see note 24). By reason of itsownership of Pertra, the Company had exposure to fluctuations inhydrocarbon prices, which historically have fluctuated widely inresponse to changing market forces. Pertra’s net productionin 2004 (combined) was 5,317,134 barrels, with anaverage realized price of $35.11 per barrel. In 2003 theaverage realized price was $29.37 per barrel.     As of December 31, 2005 and 2004, the Company did not haveany outstanding derivative commodity instruments. In the firsthalf of 2004, we sold forward 950,000 barrels of our 2004second half production at an estimated average of$30.50 per barrel. Of the total amount sold forward,250,000 barrels sold forward at an average price of$29.91 per barrel were not delivered at December 31,2004, but were delivered in early January 2005. Estimated fairvalue of the contract at December 31, 2004 was a netliability of $2.6 million, which is included in accruedexpenses in the consolidated balance sheets and in revenuesproducts in the consolidated statements of operations, based onmark-to-market rates.**NOTE 20 — Commitments and Contingencies*****Leases.***     The Company has operating lease commitments expiring at variousdates through 2015. The Company also has capital leasecommitments, primarily for onshore-based seismic equipment,expiring at various dates through 2008. At December 31,2005, future minimum payments related to non-cancelableoperating and capital leases with lease terms in excess of oneyear are as follows:             **December 31, 2005**     **Operating** **Capital**  **Leases** **Leases**       **(In thousands of dollars)**    2006 $39,194  $23,094     2007  27,318   7,308     2008  26,889   6,869     2009  24,613   —     2010  12,597   —     Thereafter  27,852   —              Total $158,463   37,271            Imputed interest      (3,571)           Net present value of capital lease obligations      33,700      Current portion of capital lease obligations      (20,495)             Long-term portion of capital lease obligations     $13,205             The Company entered into a capital lease arrangement of$0.7 million for the year ended December 31, 2005,while there were no such new arrangements for the year endedDecember 31, 2004.
F-36

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Future minimum payments related to non-cancelable operatingleases reflect $8.2 million in sublease income for 2006,related to a time-charter of one FPSO shuttle tanker to a thirdparty.     The future minimum payments under the Company’s operatingleases relate to the Company’s operations as follows:        **December 31,**  **2005**     **(In thousands**  **of dollars)**    Marine seismic and support vessels $6,267     Onshore seismic equipment  75     FPSO shuttle and storage tankers  56,821     Buildings  94,341     Fixtures, furniture and fittings  959          Total $158,463          Included in the minimum lease commitment for FPSO shuttle andstorage tankers as presented in the table above is charter hirefor the six month cancellation period for a storage tankeroperating on the Banff field in the North Sea. The Company isrequired to charter the vessel for as long as *Ramform Banff*produces the Banff field, which could extend to 2014depending on the customer/field operator. The maximum paymentfor the charter through 2014 is $97.8 million, of whichonly charter hire for the six month period ending June 30,2006 is included in the table above.     Rental expense for operating leases, including leases with termsof less than one year, was $59.6 million and$59.4 million for the years ended December 31, 2005and 2004, $12.2 million for the two months endedDecember 31, 2003 and $76.3 million for the ten monthsended October 31, 2003. Rental expense for operating leasesare net of sub-lease income related to time charter of FPSOshuttle tankers to a third party amounting to $10.0 millionand $10.3 million for the years ended December 31,2005 and 2004, $1.4 million for the two months endedDecember 31, 2003 and $16.6 million for the ten monthsended October 31, 2003.***Other.***     The Company has contingencies resulting from litigation, otherclaims and commitments incidental to the ordinary course ofbusiness. Management believes that the probable resolution ofsuch contingencies will not materially affect the financialposition, results of operations or cash flows of the Company.***UK Leases.***     The Company entered into capital leases from 1996 to 1998relating to *Ramforms Challenger, Valiant, Viking, Victory*and *Vanguard;* the FPSO *Petrojarl Foinaven;* andthe production equipment for the *Ramform Banff*. The termsfor these leases ranged from 13-25 years. The Company hasindemnified the lessors for the tax consequences resulting fromchanges in tax laws or interpretations thereof or adverserulings by the tax authorities and for variations in actualinterest rates from those assumed in the leases. There are nolimits on either of these indemnities. Reference is also made tothe description in Note 2 — UK Leases.     The lessors claim tax depreciation (capital allowances) on thecapital expenditures that were incurred for the acquisition ofthe leased assets. Although the UK Inland Revenue generallydeferred for a period of time agreeing to the capital allowancesclaimed under such leases pending the outcome of a legalproceeding in which the Inland Revenue was challenging capitalallowances associated with a defeased lease, in November 2004,the highest UK court of appeal ruled in favor of the taxpayerand rejected the position of the Inland Revenue. In connectionwith the adoption of fresh-start reporting on November 1,2003 and before the
F-37

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**November 2004 ruling, the Company recorded a liability of16.7 million British pounds (approximately$28.3 million). The Company releases applicable portions ofthis liability if and when the Inland Revenue accepts thelessors’ claims for capital allowances under each lease. In2005 the Company released 9.4 million British pounds(approximately $17.2 million) of the liability, recorded asother operating (income) expense, net (see Note 5).     The remaining accrued liability at December 31, 2005 of7.3 million British pounds (approximately$12.7 million) relates to the *Petrojarl Foinaven*lease, where the Inland Revenue has raised a separate issueabout the accelerated rate at which tax depreciation isavailable. If the Inland Revenue were successful in challengingthat rate, the lessor would be liable for increased taxes on*Petrojarl Foinaven*in early periods (and decreased taxesin later years), and the Company’s rental would increase.How much the rentals could increase depends primarily on howmuch of the asset will be subject to a different depreciationrate. Management believes that 60 million to70 million British pounds (approximately $104 millionto $121 million) represents a worst-case scenario for thisliability.     The leases are legally defeased because the Company has madeup-front payments to independent third-party banks inconsideration for which these banks have assumed liability tothe lessor equal to basic rentals and termination sumobligations. The defeased rental payments are based on assumedSterling LIBOR rates between 8% and 9% per annum. If actualinterest rates are greater than the assumed interest rates, theCompany receives rental rebates. Conversely, if actual interestrates are less than the assumed interest rates, the Company paysrentals in excess of the defeased rental payments. Over the lastseveral years, the actual interest rates have been below theassumed interest rates. Prior to November 1, 2003, theCompany had deferred a portion of a deferred gain (seeNote 2 — UK leases) representing the net presentvalue of additional required rental payments as of the inceptionof each lease. Such deferred gain was amortized over the termsof the leases. Effective November 1, 2003, the Companyadopted fresh-start reporting and recorded a liability equal tothe fair value of the future additional required rental paymentsbased on forward market rates for Sterling LIBOR and an 8%discount rate. This liability, which is amortized based onfuture rental payments, amounted to 30.5 million Britishpounds (approximately $51.6 million) at November 1,2003, 24.6 million British pounds (approximately$47.2 million) at December 31, 2004 and22.0 million British pounds (approximately$38.1 million) at December 31, 2005.     At December 31, 2005, interest rates were below the assumedinterest rates. Based on forward market rates for SterlingLIBOR, the net present value, using an 8% per annumdiscount rate, of the additional required rental paymentsaggregated 31.5 million British pounds (approximately$54.5 million) as of December 31, 2005. Of thisamount, 1.2 million British pounds (approximately$2.0 million) was accrued at December 31, 2005, inaddition to the remaining fresh-start liability as describedabove.     Additional required rental payments were $7.2 million foreach of the years ended December 31, 2005 and 2004,$4.9 million for the two months ended December 31,2003 and $1.5 million for the ten months endedOctober 31, 2003.***Brazil Service Tax Claim.***     The Company has an ongoing appeal process in Brazil related tomunicipal services tax (“ISS”), whether the Company isactually liable for ISS taxes and, if it is liable for suchtaxes, to which municipality such taxes should be paid(municipalities levy ISS tax at different rates). The appealrelates to the period 1998 through 2001 and the potentialadditional exposure for this period is $8.5 million. TheCompany is subject to additional exposure for subsequent periodsof up to $29.9 million (including potential interest andpenalties). ISS is a service tax, and the Company’s primaryview is that licensing of multi-client data should be treated asrental of an asset rather than a service, and therefore notsubject to ISS. Management’s assessment is that it isreasonably possible, but not probable, that this liability willmaterialize. Thus no accrual has been recognized.
F-38

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)****NOTE 21 — Income Taxes**     The expense (benefit) for income taxes from continuingoperations consists of the following:                       **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Current taxes:                     Norwegian $519  $(5) $394  $6,639      Foreign  10,343   20,761   1,558   15,373     Deferred taxes:                     Norwegian  —   24,534   (1,575)  2,025      Foreign  10,965   2,729   (4,226)  (3,943)                   Total $21,827  $48,019  $(3,849) $20,094                  Classification in consolidated statements of operations:                     Income tax expense (benefit)  21,827   48,019   (3,849)  21,911      Fresh start adoption  —   —   —   (1,817)                   Total income tax expense (benefit) $21,827  $48,019  $(3,849) $20,094                   The net expense (benefit) for the years ended December 31,2005 and 2004, the two months ended December 31, 2003 andthe ten months ended October 31, 2003 includes$224.7 million, $41.0 million, $3.1 million and$182.9 million, respectively, in valuation allowancesrelated to deferred tax assets (see table below).     The net expense (benefit) for the years ended December 31,2005 and 2004, and the ten months ended October 31, 2003includes $(2.7) million, $9.5 million and$2.0 million, respectively, of provisions related to theresolution of uncertainties regarding outstanding tax issues.The total accrued amount related to contingent tax liabilitiesas of December 31, 2005 was $22.3 million, of which$3.1 million was recorded as income taxes payable and$19.2 million was recorded as other long-term liabilities.As of December 31, 2004, such amount totaled$29.9 million, of which $5.3 million was recorded inincome taxes payable and $24.6 million was recorded asother long-term liabilities.     The Company evaluates the need for valuation allowances relatedto its deferred tax assets by considering the evidence regardingthe ultimate realization of those recorded assets. A valuationallowance, by tax jurisdiction, is established when it is morelikely than not that all or some portion of deferred tax assetswill not be realized. During 2005, the Company concluded thatcertain valuation allowances are no longer necessary asavailable evidence, including recent accumulated profits andestimates of projected near term future taxable income,supported a more-likely-than-not conclusion that a portion ofthe related deferred tax assets will be realized. As a resultthe Company released a portion of its valuation allowance,resulting in recognition of deferred tax assets of$20.0 million as of December 31, 2005.
F-39

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Changes in valuation allowance are as follows:                      **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Balance at the beginning of the period $405,285  $368,550  $365,439  $182,581      Current year additions  224,651   41,021   3,111   182,858      Decrease of valuation allowance from utilization and recognition    of pre-reorganization deferred tax assets  (27,114)  (4,286)  —   —      Change related to other comprehensive income, sale of    subsidiaries and minority interests  2,151   —   —   —                  Balance at the end of the period $604,973  $405,285  $368,550  $365,439                   Current year additions to the valuation allowance relate toincreases in tax losses carried forward and tax deductibletemporary differences where the Company evaluated that it ismore likely than not that the relevant deferred tax assets willnot be recognized in future periods. Current year additions tothe valuation allowance also include amounts related to deferredtax assets resulting from additional pre-reorganization tax losscarryforwards identified in 2005. There was a decrease ofvaluation allowance related to the utilization of tax benefitsfrom pre-reorganization temporary differences and losses carriedforward (for which a valuation allowance was provided at thedate of reorganization) of $27.1 million, resulting in acorresponding decrease of intangible assets for the year endedDecember 31, 2005. The $27.1 million consisted of$7.1 million current year utilization and$20.0 million related to change in judgment about theestimated future utilization of deferred tax assets. Theaggregate reduction to intangible assets consisted of reductionsof $25.3 million to multi-client library, $1.3 millionto other intangible assets and $0.5 million to otherlong-lived assets (see Notes 10, 11 and 12). Of the totalvaluation allowance as of December 31, 2005,$390.0 million relates to pre-reorganization amounts andwill, if the related deferred tax assets are subsequentlyrecognized, be allocated to reduce intangible assets existing atfresh-start (identified as multi-client library, otherintangible assets and certain favorable lease contracts(included in other long-lived assets)) or directly toshareholders’ equity if all intangible assets existing atfresh-start have been reduced to zero.
F-40

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     The expense (benefit) for income taxes from continuingoperations differs from the amounts computed when applying theNorwegian statutory tax rate to income (loss) before incometaxes as a result of the following:                        **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Income (loss) from continuing operations before income taxes,    minority interest and cumulative effect of change in accounting    principles:                      Norwegian $(103,101) $(125,179) $(16,755) $623,654       Foreign  241,071   35,421   3,198   (46,052)                    Total  137,970   (89,758)  (13,557)  577,602     Norwegian statutory rate  28%  28%  28%  28%                 Expense (benefit) for income taxes at statutory rate  38,632   (25,132)  (3,796)  161,729     Increase (reduction) in income taxes from:                     Foreign earnings taxed at other than statutory rate  (4,415)  (7,612)  (440)  (2,057)     Petroleum surtax(a)  (1,415)  12,343   (1,619)  5,908      Non-taxable gain on sale of subsidiary  (40,422)  —   —   —      Non-taxable gain on debt discharge  —   —   —   (351,078)     Other  5,655   3,047   —   —      Gain (loss) from local currency other than reporting currency  2,621   (2,578)  (1,495)  372      Current year realization of uncertain tax position not    recognized in prior years  (82,556)  —   —   —      Non-creditable foreign taxes and other permanent items  27,728   26,930   390   22,362      Change in temporary differences to intangible assets due to    utilization of pre-reorganization deferred tax assets (circle    effect)  (8,760)  —   —   —      Deferred tax asset valuation allowance  84,759   41,021   3,111   182,858                     Total income tax expense (benefit) $21,827  $48,019  $(3,849) $20,094               (a)     Pertra’s income from oil activities on the Norwegian    Continental Shelf is taxed according to the Norwegian Petroleum    Tax Law, which includes a surtax of 50% in addition to the    Norwegian corporate tax of 28%.
F-41

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Deferred tax assets and liabilities are summarized as follows:                     **December 31,**     **2005** **2004**       **Asset** **Liability** **Asset** **Liability**           **(In thousands of dollars)**    Current assets and liabilities $(4,166) $19,525  $(3,036) $1,038     Property, equipment and other long-lived assets  (137,822)  509   (23,384)  37,002     Tax losses carried forward  (447,799)  —   (262,458)  —     Deferred gain (loss)  (19,606)  22,527   (57,721)  32,971     Tax credits  (3,083)  —   (2,893)  —     Expenses deductible when paid  (47,503)  —   (84,853)  —     Other temporary differences  (6,003)  —   (6,072)  —                    Total deferred tax (assets) liabilities before valuation    allowance  (665,982)  42,561   (440,417)  71,011                  Deferred tax asset valuation allowance  604,973       405,285                        Deferred tax (assets) liabilities $(61,009) $42,561  $(35,132) $71,011                   Net deferred tax (assets) liabilities — Norwegian      (20,000)      35,514      Net deferred tax (assets) liabilities — Foreign      1,552       365                    Net deferred tax (assets) liabilities     $(18,448)     $35,879                  Classification in the consolidated balance sheets:                     Short-term deferred tax liabilities     $1,055      $761      Long-term deferred tax assets      (20,000)      —      Long-term deferred tax liabilities      497       35,118                    Net deferred tax (assets) liabilities     $(18,448)     $35,879                   Tax losses carried forward in Norway of $1,166.0 million,in the UK of $282.2 million, and in Singapore, Brazil andAustralia totaling $52.1 million can be carried forwardindefinitely. U.S. tax losses carried forward of$63.9 million expire between 2019 and 2026.     The Company does not provide Norwegian taxes on unremittedearnings of certain international operations, which reflect fullprovision for non-Norwegian income taxes, as these earnings areexpected to be reinvested outside of Norway indefinitely. Thecompany has not calculated the tax effect associated with theseunremitted earnings as it is not practicable to do so.     The Company has received a tax claim from the tax authority inSingapore relating to the years 1998 through 2002 based on theassertion that tax deductions for expenses related toinvestments in the multi-client data library would not beallowed. The possible additional exposure is $26.8 million,of which an assessment of $7.1 million has been issued forfiscal year 1998. Until 2003, the multi-client library was notautomatically subject to tax allowances if classified as anintangible asset. The Company has filed tax returns claiming taxdeductions for amortization of the multi-client library asincluded in the financial statements. The Company is currentlypreparing an appeal to the Ministry of Finance against the taxclaim, which would assert that costs incurred when acquiringdata under an exclusive license contract are tax deductible,while costs incurred when acquiring data under a non-exclusivemulti-client license contract are not tax deductible.Management’s assessment is that it is reasonably possible,but not probable, that the tax authority’s view willprevail.
F-42

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**Penalties of up to 17% of the $7.1 million that has alreadybeen assessed will accrue in 2006 if the Company does not paythe additional tax and is unsuccessful in claiming amortization.     Until January 1, 2002, a foreign subsidiary was included inthe Norwegian shipping tax regime. No deferred taxes wererecognized on unremitted earnings in this subsidiary prior tothe withdrawal from the regime as these earnings at that timewere expected to be reinvested indefinitely within the regime. Asubsequent decision in 2003 to exit with effect from 2002resulted in recognition of deferred tax liabilities of$78.8 million. The Norwegian Central Tax Office(“CTO”) has not yet finalized the 2002 tax assessmentin relation to withdrawal from the Norwegian shipping taxregime. The pending issue is related to fair value of thevessels involved. The Company based such exit values on thirdparty valuations, while the CTO has raised the issue whether theCompany’s book values at December 31, 2001, would bemore appropriate as basis for computing the tax effects of theexit. Any increase of exit values will result in an increase oftaxable exit gain and a corresponding increase in basis forfuture tax depreciation. The Company estimates that if the CTOposition is upheld, taxes payable for 2002, without consideringmitigating actions, could increase by up to $24 million.The Company believes that its calculation basis for exit hasbeen prepared using acceptable principles and will contest anyadjustment to increase taxes payable.**NOTE 22 —****Pension Obligations*****Defined Benefit Plans.***     The Company has historically had defined benefit pension plansfor substantially all of its Norwegian and UK employees, witheligibility determined by certainperiod-of-servicerequirements. In Norway these plans are generally funded throughcontributions to insurance companies. In the UK, the plans arefunded through a separate pension trust. It is theCompany’s general practice to fund amounts to these definedbenefit plans at rates that are sufficient to meet theapplicable statutory requirements. As of January 1, 2005, apart of the Norwegian plans were settled eliminating futurespouse and child-survivor benefits. Accrued benefits as of thatdate were settled with annuity contracts and employees eligibleunder these plans received apaid-up pension forearned funds covering the spouse and child portion up toDecember 31, 2004. In addition the Norwegian definedbenefit plans were closed for further entries and new definedcontribution plans established for new employees (see separatesection below). At December 31, 2005, 955 employees wereparticipating in the defined benefit plans.     Pension cost for disposed subsidiaries are included for theperiod up to the sales closing date.     Reconciliation of the plans’ aggregate projected benefitobligations and fair values of assets are summarized as follows:     Change in projected benefit obligations (PBO):            **December 31,**     **2005** **2004**       **(In thousands of dollars)**    Projected benefit obligations (PBO) at beginning of year $117,796  $101,855     Service cost  9,445   10,198     Interest cost  5,540   5,145     Employee contributions  1,033   968     Payroll tax  24   178     Actuarial (gain) loss, net  11,166   (9,532)    Benefits paid  (1,382)  (1,212)    Exchange rate effects  (15,402)  10,196             Projected benefit obligations (PBO) at end of year $128,220  $117,796        
F-43

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Change in pension plan assets:            **December 31,**     **2005** **2004**       **(In thousands of**  **dollars)**    Fair value of plan assets at beginning of year $71,565  $53,332     Adjustment at beginning of year  531   (1,214)    Return on plan assets  4,878   4,130     Employer contributions  9,848   8,383     Employee contributions  1,033   968     Benefits paid  (1,382)  (1,212)    Exchange rate effects  (8,237)  7,178             Fair value of plan assets at end of year $78,236  $71,565             The aggregate funded status of the plans and amounts recognizedin the Company’s consolidated balance sheets are summarizedas follows:            **December 31,**     **2005** **2004**       **(In thousands of dollars)**    Funded status $(49,984) $(46,232)    Unrecognized actuarial (gain) loss  9,892   (6,021)    Unrecognized prior service cost  (5,140)  —     Additional minimum liability  (211)  (219)            Net amount recognized as pension liability (Note 14) $(45,443) $(52,472)            The accumulated benefit obligation (ABO) for all definedbenefit pension plans was $111.4 million and$104.3 million as of December 31, 2005 and 2004,respectively.     Net periodic pension costs for the Company’s definedbenefit pension plans are summarized as follows.                      **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**             Service cost $9,445  $10,198  $1,204  $7,145     Interest cost  5,540   5,145   1,207   3,247     Expected return on plan assets  (4,878)  (4,130)  (819)  (2,977)    Amortization of plan changes  (335)  —   —   —     Amortization of actuarial loss (gain)  (169)  16   (80)  403     Adjustment to actuarial (gain) loss, plan changes  1,080   —   —   —     Amortization of prior service cost  —   —   —   3     Amortization of transition obligation  —   —   —   17     Adjustment to minimum liability  —   198   —   —     Administration cost  105   99   —   —     Payroll tax  1,043   949   266   397                   Net periodic pension cost $11,831  $12,475  $1,778  $8,235              
F-44

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Plans in which the accumulated benefit obligation exceeds planassets are as follows:           **December 31,**     **2005** **2004**       **(In thousands of dollars)**    Projected benefit obligation (PBO) $127,939  $112,727     Accumulated benefit obligation (ABO)  111,172   100,167     Fair value of plan assets  77,913   67,147      Assumptions used to determine net periodic pension costs:                           **Years Ended December 31,**     **2005** **2004** **2003**         **Norway** **UK** **Norway** **UK** **Norway** **UK**                 Discount rate  4.8%   5.3%   5.3%   5.3%   6.0%   5.3%     Return on plan assets  5.8%   7.5%   6.3%   7.5%   7.0%   7.5%     Compensation increase  3.2%   3.0%   3.0%   3.0%   3.0%   4.7%     Annual adjustment to pensions  3.2%   3.0%   3.0%   3.0%   3.0%   3.0%      Assumptions used to determine benefit obligations at end ofyears presented:                   **December 31,** **December 31,**  **2005** **2004**       **Norway** **UK** **Norway** **UK**             Discount rate  4.3%   4.8%   5.3%   5.3%     Compensation increase  3.2%   3.2%   3.0%   3.0%      The discount rate assumptions used for calculating pensionsreflect the rates at which the obligations could be effectivelysettled. Observable long-term rates on governmental bonds areused as a starting point and matched with the Company’sexpected cash flows under the Norwegian plans. Observablelong-term rates on corporate bonds are used for the UK plans.The expected long-term rate of return on plan assets is based onhistorical experience and by evaluating input from the trusteemanaging the plan’s assets.     The Company’s pension plan asset allocation atDecember 31, 2005 and 2004, by asset category, arepresented by major plan group as follows:                    **December 31,**     **2005** **2004**       **Norway** **UK** **Norway** **UK**           **(In thousands of dollars)**    Fair value of plan assets $38,268  $39,968  $40,111  $31,454                  Debt securities  62%  —   69%  —     Equity securities  23%  100%  16%  92%    Real estate  12%  —   12%  —     Other  3%  —   3%  8%                  Total  100%  100%  100%  100%                  Average target allocations for Norwegian plan assets are 15-30%in equity securities, 50-70% in debt securities, 10-15% in realestate and 3-10% inother. Maturities for the debt securities at December 31,2005, range from two weeks to 28 years with a weightedaverage maturity of 4.6 years. Weighted average durationfor the debt securities is 3.6 years.
F-45

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Management of plan assets must comply with applicable laws andregulations in Norway and the UK where the Company providesdefined benefits plans. Within constraints imposed by laws andregulations, and given the assumed pension obligations andfuture contribution rates, the majority of assets are managedactively to obtain a long-term rate of return that at leastreflects the chosen investment risk.     The Company expects to contribute approximately$7.0 million to its defined benefit pension plans in 2006.Total pension benefit payments expected to be paid toparticipants from the plans are as follows:       **(In thousands**  **of dollars)**    2006 $1,166     2007  1,371     2008  1,545     2009  1,719     2010  1,320     2011 through 2015  15,374 ***Defined Contribution Plans.***     Substantially all employees not eligible for coverage under thedefined benefit plans in Norway and the UK are eligible toparticipate in pension plans in accordance with localindustrial, tax and social regulations. All of these plans areconsidered defined contribution plans.     As described above under “Defined Benefit Plans,” asof January 1, 2005 the Company closed the Norwegian definedbenefit plans for further entries and new defined contributionplans were established for new employees. The Company’scontributions to these plans for the year endedDecember 31, 2005 totaled $0.2 million.     Under the Company’s U.S. defined contribution 401(k)plan, essentially all U.S. employees are eligible toparticipate upon completion of certainperiod-of-servicerequirements. The plan allows eligible employees to contributeup to 100% of compensation, subject to IRS and plan limitations,on a pre-tax basis, with a 2005 statutory cap of $14,000($18,000 for employees over 50 years). Employee pre-taxcontributions are matched by the Company as follows: the first3% are matched at 100% and the next 2% are matched at 50% ofcompensation. All contributions vest when made. The employermatching contribution recognized by the Company related to theplan was $1.3 million and $1.2 million for the yearsended December 31, 2005 and 2004, $0.2 million for thetwo months ended December 31, 2003 and $1.2 millionfor the ten months ended October 31, 2003. Contributions tothe plan by employees for these periods were $3.3 million,$3.1 million, $0.6 million and $2.7 million,respectively.     Aggregate employer and employee contributions under theCompany’s other plans for the years ended December 31,2005 and 2004, the two months ended December 31, 2003 andthe ten months ended October 31, 2003, totaled$0.6 million and $0.3 million (2005),$0.8 million and $0.4 million (2004),$0.1 million and $0.1 million (two months 2003) and$2.1 million and $0.3 million (ten months 2003).**NOTE 23 —****Share Based Compensation Plans**     In connection with the restructuring of the Company in 2003, allshares in the Company were cancelled (see Notes 1 and 3 foradditional information) and all agreements relating to shareoptions for the Company’s key employees and directors werecancelled. No new option agreements have been established sincethe restructuring. During the period in which the share-basedcompensation plan was active, the exercise price of each awardequaled the market price of the Company’s shares on thegrant date. The vesting period for granted options ranged fromapproximately three years to approximately three and one-halfyears. Once
F-46

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**vested, the exercisable life of the options was generally atwo-year period, with certain options granted during 2000 andthereafter exercisable over a three-year period. The Companyused the intrinsic value method to account for this stock-basedemployee compensation.     A summary of the status of the Company’s share-basedcompensation plans as of December 31, 2003 is summarized asfollows:           **December 31, 2003**       **Weighted**    **Average**    **Exercise**  **Options** **Price**         Outstanding at beginning of year  4,973.5   NOK135     Forfeited/cancelled  (4,973.5)  NOK135            Outstanding at December 31, 2003  —   —             If the compensation cost for the share-based compensation planshad been determined based on the fair values of the optionsawarded at the grant dates, consistent with the provisions ofSFAS 123, the net income (loss) and earnings (loss) pershare would have been affected on a pro forma basis as indicatedbelow:        **Predecessor**  **Company**     **Ten Months**  **Ended**  **October 31,**  **2003**     **(In thousands of**  **dollars, except for**  **share amounts)**    Net income, as reported $557,045     Deduct: Total share-based compensation expense determined under    the fair value based method for all awards, net of related tax    effect  (5,105)         Pro forma, net income $551,940         Net income per share:         Basic and diluted — as reported $5.39      Basic and diluted — pro forma $5.34 **NOTE 24 —****Acquisitions and Dispositions**     In 2002, the Company sold its Production Services (formerlyAtlantic Power Group) subsidiary to Petrofac Limited. TheCompany is eligible to receive an additional consideration of$2.5 million upon the occurrence of certain contingentevents through 2010.     In February 2003, the Company sold its Atlantis oil and gasactivities to Sinochem and received proceeds and reimbursementsaggregating $59.2 million. The Company was entitled toreceive up to $25.0 million in additional, contingentproceeds, which agreement was amended in June 2005. Inaccordance with the amended agreement, the Company may receive amaximum of $10.0 million in contingent proceeds upon theoccurrence of certain contingent events, which currently has notbeen recognized.     In December 2003, the Company sold its wholly owned softwarecompany PGS Tigress (UK) Ltd. for a deferred compensationof approximately $1.8 million, payable in 2004 through2007, for which payments were received in December 2005 and2004. The Company may also receive additional contingentproceeds based on
F-47

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**performance of the company through 2006. As of December 31,2005, the Company had not received any such contingent proceeds.The Company recognized no net gain or loss on the sale ofTigress.     In March 2005, the Company sold its wholly owned oil and naturalgas subsidiary Pertra AS to Talisman Energy (UK) Ltd. foran initial sales price of approximately $155 million.Pertra AS has been renamed Talisman Production Norge AS. TheCompany recognized a $149.8 million gain from the sale,including the $2.5 million received to grant an option tomake certain amendments to the charter and operating agreementfor the *Petrojarl Varg*, recognized as net gain on sale ofsubsidiaries. As part of the transaction, the Company isentitled to receive additional sales consideration equal to thevalue, on a post petroleum tax basis, of 50% of the relevantrevenues from the Varg field in excess of $240 million foreach of the years ended December 31, 2005 and 2006. InJanuary 2006, we received $8.1 million, representing the2005 portion of the contingent consideration. The Companyaccrued this amount in December 2005 and recognized the amountas additional gain on the 2005 sale (see Note 4). TheCompany also granted an option enabling Talisman to change thetermination clause with respect to PL038. The option expired onFebruary 1, 2006 without being exercised. Assets andliabilities relating to Pertra as of December 31, 2004 areshown below, while the results of operations and capitalexpenditures for the periods presented up to March 1, 2005are presented as a separate segment in our consolidatedstatements of operations (see Note 27). The operations ofPertra are not presented as discontinued operations due tocontinuing involvement through the charter of *PetrojarlVarg*.     In August 2005, the Company entered into an agreement to sellits wholly owned subsidiary PGS Reservoir AS to ReservoirConsultants Holding AS (“RCH”), which is controlled bya group of former PGS employees. RCH has the option to sell theshares back to the Company for an amount equal to theconsideration (approximately $0.5 million), which optionexpires 12 months from completion date (August 31,2005). The Company has recorded an estimated loss of$1.5 million for this transaction, recognized in net gainon sale of subsidiaries (see Note 4.) In addition theCompany recorded assets and liabilities of business transferredunder the contractual arrangement aggregating $3.5 milliongross. Such assets and liabilities are recognized in othercurrent assets and accrued expenses (see Notes 8 and 13).     The results of operations, net assets and cash flows for Tigresshave been presented as discontinued operations, and aresummarized as follows for the years presented:            **Successor Company** **Predecessor Company**       **Two Months** **Ten Months**  **Ended** **Ended**  **December 31,** **October 31,**  **2003** **2003**       **(In thousands of dollars)**    Revenues $137  $1,107            Operating expenses before depreciation, amortization, impairment    and other operating (income) expense, net  (264)  (2,433)    Depreciation and amortization  —   (707)    Other operating (income) expense, net  —   (512)            Total operating expenses  (264)  (3,652)           Operating profit (loss)  (127)  (2,545)    Interest expense and other financial items, net  24   (1,237)            Income (loss) before income taxes $(103) $(3,782)            Capital expenditures of discontinued operations $—  $118        
F-48

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     A reconciliation of income (loss) before income taxes, asreported above, and income (loss) from discontinued operations,net of tax, as presented in the Consolidated Statements ofOperations, is as follows:                      **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**             Income (loss) from discontinued operations before income taxes $—  $—  $(103) $(3,782)    Loss on disposal  —   —   (32)  —     Additional proceeds  500   3,048   —   1,500                   Loss from discontinued operations, net of tax $500  $3,048  $(135) $(2,282)                  Operating expenses relating to discontinued operations includescorporate management fees based on actual charges to theseentities. For continuing operations, such fees are presented inthe segment for Reservoir/ Shared Services/ Corporate (seeNote 27). Allocation of interest expense to discontinuedoperations is based on actual interest charged to the respectiveentities.     The operations of Pertra are presented as a separate segment inour consolidated statements of operations (see Note 27).Assets and liabilities relating to Pertra as ofDecember 31, 2004 were as follows:        **December 31, 2004**     **Pertra**     **(In thousands of**  **dollars)**    Cash and cash equivalents $13,423     Accounts receivable, net  7,406     Other current assets  15,916     Property and equipment, net  937     Oil and natural gas assets, net  70,940     Other long-lived assets  12,024          Total assets $120,646         Accounts payable $1,624     Accrued expenses  8,720     Deferred tax liabilities, current  761     Other long-term liabilities  39,942     Deferred tax liabilities, long-term  34,752          Total liabilities $85,799     
F-49

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)*****Subsequent Events.***     In February 2006, the Company announced a proposed joint venturewith Teekay Shipping Corporation to develop new FPSO projects.We expect to finalize the arrangements for the joint ventureduring the second quarter of 2006.     As described above, the Company may receive $10 million inadditional contingent proceeds, upon the occurrence of certaincontingent events, from the sale of Atlantis in 2003. AtDecember 31, 2005, the Company had not accrued for theseproceeds. In March 2006, the Company received confirmation ofthe occurrence of certain of these events that entitle theCompany to receive $6 million, of which $3 million wasreceived in March 2006.     On March 27, 2006, the Company’s Board of Directorsauthorized proceeding with a demerger plan under Norwegian lawto separate its geophysical and production businesses into twoindependently listed companies and calling an extraordinarygeneral meeting of its shareholders to vote on the transaction,to be held on April 28, 2006.     Under the proposed demerger, the Company’s subsidiarycompanies that conduct its production business, and the assets,rights and liabilities related to the production business, willbe transferred to a wholly owned subsidiary named Petrojarl ASA.The Company’s subsidiary companies that conduct itsgeophysical business, and the assets, rights and liabilitiesrelated to the geophysical business, will be retained underPetroleum Geo-Services ASA.     When the separation is completed, each holder of theCompany’s ordinary shares will receive one ordinary shareof Petrojarl for each of its shares held and each holder ofAmerican Depositary Shares (“PGS ADSs”) representingthe Company’s ordinary shares will receive one newly issuedAmerican Depositary Share representing an ordinary share inPetrojarl (“Petrojarl ADSs”) for each PGS ADSheld. The Company intends to apply for a listing of the ordinaryshares of Petrojarl ASA on the Oslo Stock Exchange. The Companydoes not intend to list the Petrojarl ordinary shares orPetrojarl ADSs in the U.S.     Immediately after consummation of the demerger, PGS ASA wouldhold shares in Petrojarl representing a 19.99% interest inPetrojarl and the Petrojarl shares issued to the holders of theCompany’s shares and the PGS ADSs would represent theremaining 80.01% interest in Petrojarl. Subject to prevailingmarket conditions and other factors, PGS ASA expects to sell theshares in Petrojarl in a public offering in conjunction with theconsummation of the separation and demerger.     If the demerger plan is approved by the requisite two-third voteof the Company’s shareholders and the conditions precedentto consummation of the demerger are satisfied, or whereapplicable waived, the Company currently expect the demerger tobe consummated in July 2006.     After completion of the demerger, PGS ASA will continue theCompany’s geophysical business and hold its assets, rightsand liabilities.     Upon consummation of the separation, the Company expects thatPetrojarl will have a new $425 million five year borrowingfacility and will initially borrow $325 million under thefacility. The proceeds from the initial borrowing, together withany proceeds from any sale of all or any part of the Petrojarlshares retained by PGS ASA, will be used by PGS ASA forrepayment of existing debt or other purposes. As part of theseparation transaction, Petrojarl will receive cash and cashequivalents of approximately $50 million and will haveapproximately $275 million of net interest-bearing debtimmediately following consummation of the separation.     In connection with the demerger, the Company has entered intoother agreements, subject to final documentation, either as partof the proposed demerger plan or otherwise, to facilitate thedemerger. For the Company’s UK leases on three of itsRamform seismic vessels and the production equipment for the
F-50

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)***Ramform Banff*, the Company has entered into agreements,subject to final documentation, with the lessors providing forcertain options with respect to the termination of the leases atreduced termination fees, subject to completion of the demerger.If all of such leases were terminated, the Company would berequired to pay termination fees of up to 13 millionBritish pounds (approximately $23 million). Upontermination, the Company and, in the case of *RamformBanff*, Petrojarl would become the owner of the assets andavoid any additional rental payments relating to these UKleases. In addition, the Company has reached an agreement,subject to final documentation, with the operator of*Petrojarl Foinaven*to provide the benefit of financialcovenants that would apply to Petrojarl following the demergerand to make other amendments to the existing contractualarrangements, in each case subject to completion of the demergerand certain other conditions. The Company will provide moredetailed information related to the separation and demerger, aswell as the other agreements, in a shareholder informationstatement prior to the extraordinary general meeting of itsshareholders called to consider the separation and demerger,which the Company expects to occur in April 2006.     The demerged Production business will be presented asheld-for-sale (discontinued operations) in the consolidatedfinancial statements from the date of board approval of thedemerger. In addition, historical financial information of thePertra operations will be presented as discontinued from thesame date, as the continued business relations with Pertrarelated to *Petrojarl Varg*will be discontinued with thedemerger of the Production business.**NOTE 25 —****Related Party Transactions**     At December 31, 2003 the Company owned 50% of the shares inGeo Explorer AS and had one vessel on charter from that company.The Company also held 100% of the shares in Walther Herwig AS(until December 11, 2003, the Company held 50% of theshares, but increased its shares as Walter Herwig AS wasde-merged) and chartered three vessels from that company in2003. Total lease expense recognized during the two months endedDecember 31, 2003 and the ten months ended October 31,2003 on these vessels was $1.1 million and$6.4 million, respectively. There were no lease expensesfor the years ended December 31, 2005 and 2004.     As of December 31, 2005, the Chairman of the Board, JensUlltveit-Moe, through Umoe AS, controlled a total of3,037,332 shares in PGS. Jens Ulltveit-Moe also has amajority ownership interest in Knutsen OAS Shipping AS(“Knutsen”). Knutsen is chartering the MT *NordicSvenita*and was also chartering the MT *Nordic Yukon*up to 2003 and paid $10.0 million, $10.3 millionand $20.1 million to the Company under time chartercontracts for the vessels in 2005, 2004 and 2003, respectively.The Company charters the vessels from an independent thirdparty. The vessels were chartered by the Company to provideshuttle services for the Banff field, but in 2001 were charteredto Knutsen on terms approximating the Company’s terms underthe third-party lease, due to low production on the Banff field.The vessel MT *Nordic Yukon*was redelivered by PGS to thevessel owner in November 2003. In addition, PGS has a contractof affreightment with Knutsen for transporting crude oilrelating to the Banff field and paid $1.2 million,$0.7 million and $2.4 million to Knutsen under thiscontract in 2005, 2004 and 2003, respectively.Mr. Ulltveit-Moe was also the Chairman of Unitor ASA untilAugust 2005, a company that from time to time provides theCompany with equipment for its vessels.***Subsequent Event.***     In January 2006 the Company entered into an agreement topurchase the shuttle tanker MT *Rita Knutsen*for$35 million from Knutsen OAS Shipping AS. The transactionwas completed March 9, 2006. The Company considers thevessel to be a possible FPSO solution for several upcomingprojects, and the Company intends to begin a conversion when afirm contract for the ship is secured. The vessel will beoperated by Knutsen OAS Shipping AS under a bareboat charteragreement until a decision to start conversion is made. JensUlltveit-Moe did not participate in any Board discussionsrelating to this transaction.
F-51

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)****NOTE 26 —****Investments in Associated Companies**     Income from associated companies accounted for using the equitymethod is as follows:                       **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Corporations and limited partnerships:                     Geo Explorer AS $(2) $26  $119  $1,425      Atlantic Explorer (IoM) Ltd.   (5)  (80)  —   —      Ikdam Production, SA  243   722   81   162      Triumph Petroleum  —   —   —   (813)     General partnerships  40   —   —   —                    Total $276  $668  $200  $774                   Investments and advances to associated companies accounted forusing the equity method are as follows:                                       **Ownership**      **Paid-In**     **Percent As**  **Book Value** **Share of** **Capital/** **Equity** **Book Value** **of**  **December 31,** **Income** **(Dividends)** **Transactions** **December 31,** **December 31,**  **2004** **2005** **2005** **2005(a)** **2005** **2005**                 Corporations and limited partnerships:                             Ikdam Production, SA $5,411  $243  $—  $(1) $5,653   40.0%     Geo Explorer AS  182   (2)  —   (15)  165   50.0%     Atlantic Explorer (IoM) Ltd.   32   (5)  —   (3)  24   50.0%     Valiant Intern. Petroleum Ltd.   —   —   68   —   68   24.6%    General partnerships  95   40   (66)  (44)  25                              Total $5,720  $276  $2  $(63) $5,935                         (a)     Includes foreign currency translation differences.**NOTE 27 —****Segment and Geographic Information**     The Company, after the sale of Pertra AS in March 2005, managesits business in three segments as follows: • *Marine Geophysical*, which consists of streamer seismic    data acquisition, marine multi-client library and data    processing;  • *Onshore*, which consists of all seismic operations on land    and in shallow water and transition zones, including onshore    multi-client library;  • *Production*, which owns and operates four harsh    environment FPSOs in the North Sea; and     Pertra AS, a small oil and natural gas company, was sold March,2005 (see Notes 4 and 24). Revenues and expenses, assetsand liabilities are included in the consolidated statementsthrough February 2005 and in
F-52

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**the comparative numbers for the years presented. The operationsof Pertra are not presented as discontinued operations due tocontinuing involvement through the lease of *PetrojarlVarg.*     The Company manages its Marine Geophysical segment from Lysaker,Norway, its Onshore segment from Houston, Texas, and itsProduction segment from Trondheim, Norway.     The principal markets for the Production segment are the UK andNorway. The Marine Geophysical and Onshore segments serve aworldwide market. Customers for all segments are primarilycomposed of major multi-national, independent and national orstate-owned oil companies. Corporate overhead has been presentedunder Reservoir/ Shared Services/ Corporate. Significantcharges, which do not relate specifically to the operations ofany one segment, such as debt refinancing and restructuringcosts, are also presented as Reservoir/ Shared Services/Corporate. Information related to discontinued operations duringany period presented has been separately aggregated. Affiliatedsales are made at prices that approximate market value. Interestand income tax expense are not included in the measure ofsegment performance.
F-53

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)*****Revenues by Segment.***     The table below presents our mix of revenues for the periodspresented:                      **Predecessor**  **Successor Company** **Company**         **Two Months** **Ten Months**  **Years Ended December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)****Marine Geophysical:**                    Contract $424,192  $297,749  $48,273  $302,451     Multi-client pre-funding  40,006   30,535   6,510   43,187     Multi-client late sales  218,781   203,397   36,786   123,435     Other  41,703   39,124   7,813   31,040                   Total Marine Geophysical  724,682   570,805   99,382   500,113              **Onshore:**                    Contract  122,415   110,288   18,442   106,324     Multi-client pre-funding  16,148   12,761   1,807   14,636     Multi-client late sales  13,976   10,112   1,210   8,005                   Total Onshore  152,539   133,161   21,459   128,965              **Production:**                *Petrojarl I*  53,394   61,303   11,086   58,529 *Petrojarl Foinaven*  89,191   96,595   18,726   93,373 *Ramform Banff*  46,483   51,509   6,572   38,616 *Petrojarl Varg*  89,920   87,133   8,604   59,191     Other  1,689   1,662   241   349                   Total Production  280,677   298,202   45,229   250,058     Reservoir/ Shared Services/ Corporate  19,418   20,852   4,957   16,243     Elimination inter-segment revenues  (17,732)  (77,686)  (8,200)  (45,612)             **Total revenues services**  1,159,584   945,334   162,827   849,767 **Revenues products — Pertra**  36,742   184,134   9,544   112,097              **Total revenues** $1,196,326  $1,129,468  $172,371  $961,864                   Additional segment information for the periods presented issummarized as follows:                                       **Reservoir/** **Elimination**            **Shared** **of**    **Marine**       **Services/** **Inter-Segment**    **Geophysical** **Onshore** **Production** **Pertra** **Corporate** **Items** **Total**                 **(In thousands of dollars)****Depreciation and amortization:**                                2005 (Successor) $172,349  $31,665  $44,064  $6,710  $4,567  $—  $259,355     2004 (Successor)  241,712   39,885   44,561   38,965   3,239   —   368,362     2003 (Successor — two months)  39,351   6,224   8,112   743   1,269   —   55,699     2003 (Predecessor — ten months)  191,215   29,425   43,418   30,826   6,692   —   301,576 
F-54

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**                                       **Reservoir/** **Elimination**            **Shared** **of**    **Marine**       **Services/** **Inter-Segment**    **Geophysical** **Onshore** **Production** **Pertra** **Corporate** **Items** **Total**                 **(In thousands of dollars)****Segment operating profit:**                                2005 (Successor) $150,229  $(9,803) $43,491  $(1,507) $(25,789) $924  $157,545     2004 (Successor)  (34,980)  (4,535)  77,769   28,120   (20,986)  (1,593)  43,795     2003 (Successor — two months)  1,772   1,778   11,878   (3,198)  (476)  —   11,754     2003 (Predecessor — ten months)  41,782   19,741   66,876   17,236   (19,475)  —   126,160 **Impairment of long-lived assets:**                                2005 (Successor) $4,575  $—  $—  $—  $—  $—  $4,575     2004 (Successor)  —   —   —   —   —   —   —     2003 (Successor — two months)  —   —   —   —   —   —   —     2003 (Predecessor — ten months)  89,598   5,085   328   —   —   —   95,011 **Net (gain) on sale of subsidiaries:**                                2005 (Successor) $—  $—  $—  $—  $(156,382) $—  $(156,382)    2004 (Successor)  —   —   —   —   —   —   —     2003 (Successor — two months)  —   —   —   —   —   —   —     2003 (Predecessor — ten months)  —   —   —   —   —   —   — **Other operating (income) expense, net:**                                2005 (Successor) $(8,847) $—  $—  $—  $(17,248) $—  $(26,095)    2004 (Successor)  (13)  9   —   —   8,116   —   8,112     2003 (Successor — two months)  1,189   38   —   —   (175)  —   1,052     2003 (Predecessor — ten months)  8,107   266   —   —   12,951   —   21,324 **Operating profit:**                                2005 (Successor) $154,501  $(9,803) $43,491  $(1,507) $147,841  $924  $335,447     2004 (Successor)  (34,967)  (4,544)  77,769   28,120   (29,102)  (1,593)  35,683     2003 (Successor — two months)  583   1,740   11,878   (3,198)  (301)  —   10,702     2003 (Predecessor — ten months)  (55,923)  14,390   66,548   17,236   (32,426)  —   9,825 **Income (loss) from discontinued operations, net of tax:(a)**                                2005 (Successor) $—  $—  $500  $—  $—  $—  $500     2004 (Successor)  —   —   3,048   —   —   —   3,048     2003 (Successor — two months)  (135)  —   —   —   —   —   (135)    2003 (Predecessor — ten months)  (3,782)  —   1,500   —   —   —   (2,282)**Cumulative effect of change in accounting principles, net of    tax**                                2005 (Successor) $—  $—  $—  $—  $—  $—  $—     2004 (Successor)  —   —   —   —   —   —   —     2003 (Successor — two months)  —   —   —   —   —   —   —     2003 (Predecessor — ten months)  (779)  —   3,168   —   —   —   2,389 **Investment in associated companies:**                                December 31, 2005 $278  $—  $5,653  $—  $4  $—  $5,935     December 31, 2004  235   —   5,411   —   74   —   5,720 **Total assets:**                                December 31, 2005 $797,316  $98,823  $676,337  $—  $145,096  $—  $1,717,572     December 31, 2004  795,102   90,451   710,521   120,646   135,433   —   1,852,153 
F-55

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**                                       **Reservoir/** **Elimination**            **Shared** **of**    **Marine**       **Services/** **Inter-Segment**    **Geophysical** **Onshore** **Production** **Pertra** **Corporate** **Items** **Total**                 **(In thousands of dollars)****Additions to long-lived tangible assets:(b)**                                2005 (Successor) $118,442  $21,055  $11  $103  $6,629  $(83) $146,157     2004 (Successor)  87,742   10,817   988   84,991   5,088   (114)  189,512     2003 (Successor — two months)  13,715   5,182   1,662   4,424   463   —   25,446     2003 (Predecessor — ten months)  71,299   21,965   (1,147)  29,741   1,349   —   123,207 **Capital expenditures on discontinued operations:(a)**                                2005 (Successor) $—  $—  $—  $—  $—  $—  $—     2004 (Successor)  —   —   —   —   —   —   —     2003 (Successor — two months)  —   —   —   —   —   —   —     2003 (Predecessor — ten months)  118   —   —   —   —   —   118      (a)    Income (loss) from discontinued operations, net of tax, and    capital expenditures on discontinued operations, included in    segment data for Marine Geophysical and Production relates to    Tigress and Production Services, respectively.     (b)    Consists of cash investments in multi-client library and capital    expenditures.     Reconciliation of segment operating profit, presented in thetable above, to income (loss) before income tax expense(benefit) and minority interest, is as follows:                      **Predecessor**  **Successor Company** **Company**         **Two Months** **Ten Months**  **Years Ended December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Segment operating profit $157,545  $43,795  $11,754  $126,160     Other segment allocated amounts (as presented in the table    above):                     Impairment of long-lived assets  4,575   —   —   95,011      Net (gain) on sale of subsidiaries  (156,382)  —   —   —      Other operating (income) expense, net  (26,095)  8,112   1,052   21,324                  Operating profit  335,447   35,683   10,702   9,825     Unallocated amounts:                     Income from associated companies  276   668   200   774      Interest expense  (96,356)  (110,811)  (16,870)  (98,957)     Debt redemption and refinancing costs  (107,315)  —   —   —      Other financial items, net  5,918   (10,861)  (4,264)  (1,472)     Gain on debt discharge  —   —   —   1,253,851      Fresh-start adoption  —   —   —   (532,268)     Cost of reorganization  —   (3,498)  (3,325)  (52,334)                 Income (loss) before income tax expense (benefit) and    minority interest $137,970  $(88,819) $(13,557) $579,419              
F-56

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Since the Company provides services worldwide to the oil andnatural gas industry, a substantial portion of the property andequipment is mobile, and the respective locations at the end ofthe period (as listed in the table below, together withmulti-client library and oil and natural gas assets) are notnecessarily indicative of the earnings of the related propertyand equipment during the period. The geographic classificationof income statement amounts listed below is based upon locationof performance or, in the case of multi-client seismic datasales, the area where the survey was physically conducted.     Information by geographic region is summarized as follows:                                               **Elimination**                **of**              **Middle East/** **Inter-Segment**    **Americas** **UK** **Norway** **Asia/Pacific** **Africa** **Other** **Items** **Total**                   **(In thousands of dollars)****Revenue, external customers:**                                    2005 (Successor) $311,496  $175,440  $306,158  $199,107  $139,317  $64,808  $—  $1,196,326     2004 (Successor)  267,054   191,745   336,949   191,703   112,503   29,514   —   1,129,468     2003 (Successor — two months)  49,164   30,743   33,087   35,175   20,784   3,418   —   172,371     2003 (Predecessor — ten months)  270,095   181,595   235,663   82,980   124,601   66,930   —   961,864 **Revenue, includes inter- segment:**                                    2005 (Successor) $312,394  $176,053  $309,349  $199,826  $139,679  $65,186  $(6,161) $1,196,326     2004 (Successor)  267,054   194,712   343,736   191,703   112,503   29,514   (9,754)  1,129,468     2003 (Successor — two months)  49,164   31,067   35,429   35,175   20,784   3,418   (2,666)  172,371     2003 (Predecessor — ten months)  270,095   183,371   238,543   82,980   124,601   66,930   (4,656)  961,864 **Total assets:**                                    December 31, 2005 $302,774  $940,263  $380,898  $73,801  $10,663  $9,173  $—  $1,717,572     December 31, 2004  343,484   927,172   469,675   79,873   21,211   10,738   —   1,852,153 **Capital expenditures (cash):**                                    2005 (Successor) $19,183  $63,679  $5,195  $1,579  $—  $854  $—  $90,490     2004 (Successor)  7,955   40,812   96,813   1,975   —   817   —   148,372     2003 (Successor — two months)  5,464   1,005   9,294   222   —   —   —   15,985     2003 (Predecessor — ten months)  6,261   6,155   27,952   136   —   1,561   —   42,065      Export sales from Norway to unaffiliated customers did notexceed 10% of gross revenue for the years endedDecember 31, 2005, 2004 and 2003.
F-57

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     For the years ended December 31, 2005, 2004 and 2003,customers exceeding 10% of the Company’s total revenue wereas follows (the table shows percentage of revenues accounted forby each of such customers, and the segments that had sales tothe respective customers are marked with X):                               **Years Ended December 31,**     **2005** **2004** **2003**         **13%** **10%** **25%** **10%** **19%** **12%** **10%**               **Segments serving customer (each % in each year represents a    separate customer):**                                Marine Geophysical  X   X   X   X   X   X   X     Onshore      X                   X     Production  X   X   X   X   X   X         Pertra  X       X       X             Reservoir/ Shared Services/ Corporate  X       X       X              In certain of the regions where the Company operates, asignificant share of its employees is organized in labor unions.Similarly the Company’s operations in certain regions aremembers of employer unions. Therefore, the Company may beaffected by labor conflicts involving such labor and employerunions.**NOTE 28 — Supplemental Cash FlowInformation**     Cash paid during the year includes payments for:                     **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Interest, net of capitalized interest $91,724  $106,731  $19,619  $120,162     UK lease, additional required rental payments (Note 20)  7,180   7,196   4,953   1,473     Income taxes  14,572   29,751   4,951   8,145      The Company entered into capital lease agreements for newequipment aggregating $0.7 million for the year endedDecember 31, 2005 and $0.6 million for the ten monthsended October 31, 2003. There were no new capital leaseagreements during the year ended December 31, 2004 or thetwo months ended December 31, 2003.**NOTE 29 — Summarized Financial Information forSubsidiaries with Debt Securities**     PGS Geophysical AS, a Norwegian corporation, is a wholly ownedsubsidiary of the Company. PGS Geophysical AS is the largestgeophysical services company within the PGS group of companies.PGS Geophysical AS is also the lessee of the *Ramform Explorer*and the *Ramform Challenger*seismic vessels. PGS ASA(parent company) has fully and unconditionally guaranteed PGSGeophysical AS charter obligations in connection with certaindebt securities issued in order to finance the purchase of thesevessels. Summarized financial information for PGS Geophysical ASand its consolidated subsidiaries is presented below. Thisinformation was derived from the financial statements preparedon a stand-alone basis in conformity with U.S. GAAP.Separate financial statements and other disclosures with respectto PGS Geophysical AS are omitted because the informationcontained therein, in light of the information contained in theconsolidated financial statements of the Company, would not bematerial.
F-58

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     The PGS Geophysical AS summarized financial information consistsof the following:                      **Predecessor**  **Successor Company** **Company**       **Years Ended** **Two Months** **Ten Months**  **December 31,** **Ended** **Ended**    **December 31,** **October 31,**  **2005** **2004** **2003** **2003**           **(In thousands of dollars)**    Income Statement Data:                     Revenue $332,190  $257,609  $17,610  $244,605      Operating profit (loss)  18,423   (4,761)  (26,009)  (4,238)     Net income (loss)  6,376   (22,868)  (12,671)  (6,752)    Balance Sheet Data:                     Current assets $90,433  $116,910  $99,453          Non-current assets  185,535   190,874   148,951          Current liabilities  96,168   56,573   84,523          Non-current liabilities  142,686   327,199   408,479          Equity (deficit)  37,114   (75,988)  (244,598)         Both Oslo Explorer PLC (“Explorer”) and OsloChallenger PLC (“Challenger”), Isle of Man publiclimited companies, are wholly owned subsidiaries of the Company,purchased in April 1997. Explorer and Challenger own the*Ramform Explorer*and the *Ramform Challenger*,respectively, and lease these vessels to PGS Geophysical ASpursuant to long-term bareboat charters. *Explorer*and*Challenger*are jointly and severally liable under the8.28% First Preferred Mortgage Notes (see Note 16), in anoriginal principal amount of $165.7 million, which wereissued to finance the purchase of the *Ramform Explorer*and the *Ramform Challenger.* Summarized financialinformation for each of *Explorer*and *Challenger*ispresented below. This information was derived from the financialstatements prepared on a stand-alone basis in conformity withU.S. GAAP. Separate financial statements and otherdisclosures with respect to Explorer and Challenger are omittedbecause the information, in light of the information containedin the consolidated financial statements of the Company, wouldnot be material.
F-59

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     The Oslo Explorer PLC and Oslo Challenger PLC summarizedfinancial information consists of the following:                                    **Successor Company** **Predecessor Company**       **Years Ended December 31,**                 **Two Months Ended** **Ten Months Ended**  **2005** **2004** **December 31, 2003** **October 31, 2003**           **Explorer** **Challenger** **Explorer** **Challenger** **Explorer** **Challenger** **Explorer** **Challenger**                   **(In thousands of dollars)**    Income Statement Data:                                     Revenue $5,064  $5,455  $5,491  $5,858  $1,164  $1,169  $5,820  $5,844      Operating profit  4,883   5,273   5,346   5,713   (6,732)  (4,562)  5,693   5,717      Net income (loss)  766   1,157   799   1,166   (7,557)  (5,387)  1,566   1,590     Balance Sheet Data:                                     Current assets $—  $—  $—  $—  $—  $—              Non-current assets  51,375   54,101   56,866   59,200   61,192   63,158              Current liabilities  6,280   6,280   6,611   6,611   6,252   6,251              Non-current liabilities  38,211   38,213   44,137   44,138   49,621   49,622              Equity  6,884   9,608   6,118   8,451   5,319   7,285         **NOTE 30 — Supplemental Information —Oil and Gas Reserves and Costs (Unaudited)**     In March 2005, the Company sold its oil and natural gassubsidiary Pertra AS to Talisman Energy (UK) Ltd. (seeNote 24). Pertra did not meet the significant activitiesrequirements for the year ended December 31, 2005. TheCompany meets the significant activities requirements for theyear ended December 31, 2004, the two months endedDecember 31, 2003 and the ten months ended October 31,2003. However, it is not considered material to the disclosureto separately present the changes in reserves or the changes inStandardized Measure for the Predecessor and Successor periodsduring the years ended December 31, 2004 and 2003.     Pertra had proved oil reserves associated with its 70% interestin PL 038 on the NCS. The Company, through its MarineGeophysical segment, also owns some small overriding royaltyinterests in oil and natural gas production offshore in the USGulf of Mexico. The supplemental financial and oil and naturalgas reserve information and standardized measure of future cashflows from proved reserves are presented for Pertra only. Theoverriding royalties financial results and oil and naturalreserves are not considered material for disclosure. Inaddition, Pertra employed a Company FPSO to produce oil from PL038. The revenues and expenses from this FPSO are eliminated inconsolidation, but the expenses are presented gross for thissupplemental presentation. As a result, the oil and natural gasresults in this supplemental disclosure will not match theresults in the consolidated statements of operations.***Financial Results Related to Oil and Natural Gas    Activities.***     The Successor results of operations, capitalized costs and costsincurred are based on the successful efforts method ofaccounting for oil and natural gas activities. The Predecessorresults of operations and costs incurred are based on the SECfull cost method. See Note 2 for the description of eachmethod. These methods may create significant differences inresults, primarily because of differences in the capitalizationpolicies under each method. As a result, the Successor andPredecessor results of operations, capitalized costs and costsincurred information are not comparable.
F-60

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)**     Results of operations relating to oil and natural gas producingactivities are as follows:                   **Predecessor**  **Successor Company** **Company**         **Two Months** **Ten Months**  **Year Ended** **Ended** **Ended**  **December 31,** **December 31,** **October 31,**  **2004** **2003** **2003**         **(In thousands of dollars)**    Oil revenues (Revenues products) $184,134  $9,544  $112,097     Production costs  93,036   6,354   62,296     Other operating costs  3,952   599   2,126     Accretion of asset retirement obligation  1,664   271   1,821     Exploration costs  20,062   4,344   —     Depletion, depreciation and amortization  38,965   743   30,826                Results of operations before tax  26,455   (2,767)  15,028                Income tax expense (benefit)  20,635   (2,159)  11,722                 Results of operations $5,820  $(609) $3,306                The above table does not include any amounts for allocatedselling, general and administrative expense or finance income orexpense.     Capitalized costs relating to oil and natural gas producingactivities are set forth below:         **December 31,**  **2004**     **(In**  **thousands of**  **dollars)**    Capitalized Costs:         Proved properties $106,604      Unproved properties  4,000      Accumulated depreciation, depletion and amortization  (39,664)          Net $70,940          As a supplemental disclosure, under the full cost method thedepletion, depreciation and amortization rate for thePredecessor for the ten months ended October 31, 2003 was$8.65 per barrel of oil produced.     Following is a summary of costs incurred in oil and natural gasexploration and development activities:                  **Predecessor**  **Successor Company** **Company**         **Two Months** **Ten Months**  **Year Ended** **Ended** **Ended**  **December 31,** **December 31,** **October 31,**  **2004** **2003** **2003**         **(In thousands of dollars)**    Exploration costs $20,062  $13,262  $16,253     Development costs  76,342   4,375   10,318                Total costs incurred $96,404  $17,637  $26,571           
F-61

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)*****Proved Reserves and Standardized Measure.***     The estimates of proved oil and natural gas reserves for Pertraas of December 31, 2004 was prepared by the Company’sengineers in accordance with guidelines established by the SECand the FASB, which require that reserve estimates be preparedunder existing economic and operating conditions with noprovision for price and cost escalations except by contractualarrangements. The estimates were reviewed by an independentreservoir engineering consultant. All of Pertra’s provedreserves are located in the Norwegian North Sea. The reserveestimates as of December 31, 2004 utilize oil prices of$40.24 per barrel (reflecting adjustments for oil quality).The Company’s actual average sale price for oil produced in2004 was $35.11 per barrel, compared to $29.37 perbarrel in 2003.     Oil and natural gas reserve quantity estimates are subject tonumerous uncertainties inherent in the estimation of quantitiesof proved reserves and in the projection of future rates ofproduction and the timing of development expenditures. Theaccuracy of such estimates is a function of the quality ofavailable data and of engineering and geological interpretationand judgment. Results of subsequent drilling, testing andproduction may cause either upward or downward revision ofprevious estimates. Further, the volumes considered to becommercially recoverable fluctuate with changes in prices andoperating costs. Reserve estimates are inherently imprecise, andestimates of new discoveries are more imprecise than those ofcurrently producing oil and natural gas properties. Accordingly,these estimates are expected to change as additional informationbecomes available in the future.     The oil and natural gas proved reserve quantities and changes inreserve quantities, the Standardized Measure of Future Net CashFlows from Proved Reserves (Standardized Measure) and thechanges in Standardized Measure are presented for the yearsended December 31, 2004 and 2003 and as ofDecember 31, 2004, respectively. A company is required todisclose this information when it has significant oil andnatural gas exploration and production activities.     The following tables provide a roll-forward of total provedreserves for the years ended December 31, 2004 and 2003, aswell as proved developed reserves at year end, as of thebeginning and end of each respective year, the StandardizedMeasure as of December 31, 2004 and 2003 and the changes inStandardized Measure for the years ended December 31, 2004and 2003:**Estimated Quantities of Reserves (Unaudited)**         **December 31,**  **2004**     **(In thousands of**  **dollars)****Crude Oil:**        Proved Reserves:         Beginning of the year  7,818       Extensions and discoveries  2,976       Revisions of previous estimates  —       Production  (5,317)         End of year  5,477         Proved Developed Reserves:         Beginning of year  2,114          End of year  5,477     
F-62

Table of Contents
**PETROLEUM GEO-SERVICES ASA AND SUBSIDIARIES****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —(Continued)****Standardized Measure of Future Net Cash Flows from ProvedReserves (Unaudited)**        **December 31,**  **2004**     **(In thousands**  **of dollars)**    Future cash inflows $220,440     Future production costs  108,253     Future development costs  —     Future abandonment costs  47,391     Future income taxes  51,762     Future net cash flows  13,034          Discount at 10% per annum  (2,288)        Standardized Measure $15,322     **Changes in Standardized Measure (Unaudited)**        **December 31,**  **2004**     **(In thousands**  **of dollars)**    Standardized Measure at beginning of year $15,731          Revisions of reserves proved in prior years  —      Changes in prices and production costs  10,636      Changes in estimates of future development and abandonment costs  (4,847)     Net change in income taxes  1,757      Accretion of discount  1,573      Other, primarily timing of production  10,454      Extensions, discoveries and other additions, net of future    production and development cost  58,216      Sales of oil and natural gas produced, net of production costs  (91,098)     Previously estimated development and abandonment costs incurred    during the period  12,900         Net changes in Standardized Measure  (409)        Standardized Measure at end of year $15,322     
F-63

Table of Contents
**EXHIBIT INDEX**       **Exhibit**    **Number**   **Description**      1.1     —     Articles of Association, as amended (unofficial English    translation)  2.1     —     Deposit Agreement, dated as of May 25, 1993, among    Petroleum Geo-Services (the “Company”), Citibank,    N.A., as depositary (the “Depositary”), and all    holders from time to time of American Depositary Receipts issued    thereunder (incorporated by reference to Exhibit (a)(1) of    Post-Effective Amendment No. 1 to the Company’s    Registration Statement on Form F-6 (Registration    No. 33-61500))  2.2     —     First Amendment to Deposit Agreement, dated as of April 24,    1997, among the Company, the Depositary and all holders from    time to time of American Depositary Receipts issued thereunder    (incorporated by reference to Exhibit (a)(2) of the    Company’s Registration Statement on Form F-6    (Registration No. 333-10856))  2.3     —     Form of American Depositary Receipt (incorporated by reference    to filing under Rule 424(b)(3) relating to the    Company’s Registration Statements on Form F-6    (Registration No. 333-122046))     The Company and its consolidated subsidiaries are party toseveral debt instruments under which the total amount ofsecurities authorized does not exceed 10% of the total assets ofthe Company and its subsidiaries on a consolidated basis.Pursuant to paragraph 2(b)(i) of the instructions to theexhibits toForm 20-F, theCompany agrees to furnish a copy of such instruments to the SECupon request.        4.1     —     Contract of Employment dated 26 January 2006 between the Company    and Svein Rennemo  4.2     —     2004 CEO Bonus Scheme (incorporated by reference to    Exhibit 4.3 of the 2003 Form 20-F)  4.3     —     Credit Agreement, dated as of December 16, 2005, among the    Company, certain of its subsidiaries and the lender parties    thereto  8.1     —     Subsidiaries (included in Item 4 of the annual report)  11.1     —     Code of Conduct (incorporated by reference to Exhibit 11.1    of the 2004 Form 20-F)  12.1     —     Certification of Chief Executive Officer pursuant to    Section 302 of the Sarbanes-Oxley Act of 2002 and    Rule 13a-14(a) of the Securities Exchange Act of 1934  12.2     —     Certification of Chief Financial Officer pursuant to    Section 302 of the Sarbanes-Oxley Act of 2002 and    Rule 13a-14(a) of the Securities Exchange Act of 1934  13.1     —     Certification of the Chief Executive Officer and the Chief    Financial Officer pursuant to Section 906 of the    Sarbanes-Oxley Act of 2002 and Rule 13a-14(b) of the    Securities Exchange Act of 1934  15.1     —     Audit Committee Charter (incorporated by reference to    Exhibit 15.1 of the 2004 Form 20-F)  15.2     —     Remuneration Committee Charter (incorporated by reference to    Exhibit 15.2 of the 2004 Form 20-F)  15.3     —     Consent of Ernst & Young AS