<PAGE>

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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   FORM 20-F

        [ ]   REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR(g) OF
                      THE SECURITIES EXCHANGE ACT OF 1934

                                       OR

             [X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

                                       OR

           [ ]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934
             FOR THE TRANSITION PERIOD FROM           TO

                        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-1366 LYSAKER, NORWAY
                    (Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:
                                      None

Securities registered or to be registered pursuant to Section 12(g) of the Act:

                 AMERICAN DEPOSITARY SHARES, EACH REPRESENTING
              ONE ORDINARY SHARE OF NOMINAL VALUE NOK 30 PER SHARE

 Securities for which there is a reporting obligation pursuant to Section 15(d)
                                of the Act: None

     Indicate the number of outstanding shares of each of the issuer's classes
of capital or common stock as of the close of the period covered by the annual
report: 20,000,000 ordinary shares, nominal value NOK 30 per share.

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

                            Yes [X]          No [ ]

     Indicate by check mark which financial statement the registrant has elected
to follow.

                        Item 17 [ ]          Item 18 [X]

     Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Sections 12, 13 or 15(d) of the Securities
Exchange Act of 1934 subsequent to the distribution of securities under a plan
confirmed by a court.
                            Yes [X]          No [ ]
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<PAGE>

                           PETROLEUM GEO-SERVICES ASA

                       ANNUAL REPORT ON FORM 20-F FOR THE
                          YEAR ENDED DECEMBER 31, 2003

                               TABLE OF CONTENTS

<Table>
<Caption>
                                                                               PAGE
                                                                               ----
<S>              <C>                                                           <C>
Petroleum Geo-Services ASA...................................................    3
Where You Can Find More Information..........................................    3
Restatement of Historical Financial Statements...............................    3
Forward-Looking Information..................................................    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..................................   17
ITEM 5.          Operating and Financial Review and Prospects................   35
ITEM 6.          Directors, Senior Management and Employees..................   55
ITEM 7.          Major Shareholders and Related Party Transactions...........   61
ITEM 8.          Financial Information.......................................   62
ITEM 9.          The Offer and Listing.......................................   63
ITEM 10.         Additional Information......................................   65
ITEM 11.         Quantitative and Qualitative Disclosures About Market          75
                   Risk......................................................
ITEM 12.         Description of Securities Other Than Equity Securities......   76

                                      PART II
ITEM 13.         Defaults, Dividend Arrearages and Delinquencies.............   77
ITEM 14.         Material Modifications to the Rights of Security Holders and   77
                   Use of Proceeds...........................................
ITEM 15.         Controls and Procedures.....................................   77
ITEM 16A.        Audit Committee Financial Expert............................   80
ITEM 16B.        Code of Ethics..............................................   80
ITEM 16C.        Principal Accountant Fees and Services......................   80
ITEM 16D.        Exemptions from the Listing Standards for Audit                81
                   Committees................................................
ITEM 16E.        Purchases of Equity Securities by the Issuer and Affiliated    81
                   Purchasers................................................

                                     PART III
ITEM 17.         Financial Statements........................................   82
ITEM 18.         Financial Statements........................................   82
ITEM 19.         Exhibits....................................................   83
</Table>

                                        2
<PAGE>

                           PETROLEUM GEO-SERVICES ASA

     As used in this annual report, we refer to Petroleum Geo-Services ASA, its
predecessors and its majority-owned subsidiaries as "we" or "us" or "our,"
unless the context clearly indicates otherwise. As discussed more fully
elsewhere in this annual report,

     - during the second half of 2002, we experienced a substantial makeover of
       our senior management and appointed a new non-executive chairman of the
       board, a new chief executive officer and a new interim chief financial
       officer, who was replaced in January 2004 with a permanent chief
       financial officer;

     - during 2003 we effected a financial restructuring of our parent holding
       company through a reorganization under Chapter 11 of the U.S. Bankruptcy
       Code in which we reduced our outstanding indebtedness by approximately
       $1,283 million; and

     - upon our emergence from Chapter 11 proceedings in November 2003, a new
       board of directors took office.

                      WHERE YOU CAN FIND MORE INFORMATION

     We have filed this annual report on Form 20-F with the Securities and
Exchange Commission under the Securities Exchange Act of 1934. Statements made
in this annual report as to the contents of any agreement or other document
referred to are not necessarily complete. For each such agreement or other
document filed as an exhibit herewith, we urge you to refer to the exhibit for a
more complete description of the matter involved. We are subject to the
informational requirements of the Exchange Act that apply to foreign private
issuers and file or furnish reports and other information with the SEC. Reports
and other information we file with or furnish to the SEC, including this annual
report, may be inspected and copied at the public reference facilities of the
SEC at 450 Fifth Street N.W., Washington D.C. 20549. Additionally, information
that we file electronically with the SEC may also be obtained from its Internet
site at http://www.sec.gov and our Internet site at http://www.pgs.com.

                 RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS

     In November 2004, our current independent auditor, Ernst & Young AS,
completed a re-audit of our 2001 financial statements under United States
generally accepted accounting principles ("U.S. GAAP"). This re-audit resulted
in a cumulative net reduction of our previously reported shareholders' equity as
of January 1, 2001 of $204.3 million and a reduction in our previously reported
net income (loss) for the year ended December 31, 2001 of $176.9 million. For a
further discussion of the impact of the restatement on our selected financial
information, please read "Operating and Financial Review and Prospects --
Restatement of Previously Issued Audited Financial Statements" in Item 5 of this
annual report. For a detailed discussion of the factors leading to the
restatement and the financial impact of the restatement, please read note 4 of
the notes to our consolidated financial statements in Item 18 of this annual
report.

                          FORWARD-LOOKING INFORMATION

     Some of the statements contained in this annual report are "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. They include such matters
as:

     - market conditions, competitive factors, expansion, technological
       developments and other trends in the businesses in which we operate;

     - business strategies;

     - maintaining and obtaining contracts for our floating production, storage
       and offloading vessels and the estimated productive lives of the fields
       served by such vessels;

                                        3
<PAGE>

     - utilization of our seismic vessels and equipment;

     - acquisition of contract and multi-client seismic data and expected future
       sales of seismic data;

     - future capital expenditures and investments in our businesses;

     - amortization charges for our multi-client library;

     - estimates of quantities of our proved oil and natural gas reserves and
       the timing and amount of future production;

     - statements about the expected drilling of wells and other planned
       activities relating to the development of our oil and natural gas
       properties;

     - governmental and tax regulations and enforcement;

     - future exposure to currency devaluations or exchange rate fluctuations;

     - interest rates; and

     - availability of a public trading market for our securities.

     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 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, or a
combination of these assumptions, uncertainties or other factors, could
materially affect our future results of operations, financial position, cash
flows and whether the forward-looking statements ultimately prove to be
accurate. These forward-looking statements are not guarantees of our future
performance, and our actual results, financial position, cash flows and future
developments may differ materially from those projected in the forward-looking
statements. When considering these forward-looking statements, you should keep
in mind the risk factors and other cautionary statements disclosed elsewhere in
this annual report, including those described under "Key Information -- Risk
Factors" in Item 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 "L" are to British pounds sterling.

                                        4
<PAGE>

                                     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. GAAP, our selected
consolidated financial data as of December 31, 2003, 2002 and 2001 and for the
period from November 1, 2003 through December 31, 2003, the period from January
1, 2003 through October 31, 2003 and for the years ended December 31, 2002 and
2001. We have derived the financial data presented below for such periods and as
of such dates from our consolidated financial statements included in Item 18 of
this annual report. The financial data presented below excludes our Production
Services subsidiary, Atlantis oil and natural gas subsidiary and PGS Tigress
software subsidiary, which were sold in 2002 and 2003 and are presented as
discontinued operations in our financial statements for all periods. You should
read the financial data in conjunction with "Operating and Financial Review and
Prospects" in Item 5 of this annual report and our consolidated financial
statements and related notes included in Item 18 of this annual report. The
financial data presented below are qualified in their entirety by reference to
those consolidated financial statements and related notes.

     We operated our business as a debtor-in-possession subject to the
jurisdiction of the U.S. Bankruptcy Court beginning on July 29, 2003, the date
that we filed a petition for protection and a reorganization plan under Chapter
11 of the U.S. Bankruptcy Code, until November 5, 2003. Accordingly, we have
prepared our post-reorganization consolidated financial statements in accordance
with the American Institute of Certified Public Accountants Statement of
Position 90-7, "Financial Reporting by Entities in Reorganization Under the
Bankruptcy Code," or SOP 90-7.

     The reorganization plan became effective and was substantially consummated
on November 5, 2003, at which time we emerged from Chapter 11. Under the plan,
our then-existing bank debt and outstanding senior notes were canceled in
exchange for a combination of new senior notes, a new term loan, new ordinary
shares and the right to receive cash. For additional information about our
Chapter 11 reorganization, please read "Operating and Financial Review and
Prospects -- Financial Restructuring" in Item 5 of this annual report and note 3
of the consolidated financial statements included in Item 18 of this annual
report.

     We adopted fresh-start reporting upon our emergence from Chapter 11
reorganization in accordance with SOP 90-7. For financial reporting purposes,
the effects of the completion of the reorganization plan and adjustments for
fresh-start reporting have been recorded as of November 1, 2003. Under
fresh-start reporting, a new entity was deemed created for financial reporting
purposes, and the carrying values of our assets were adjusted to their
reorganization values, which are equivalent to their estimated fair values at
November 1, 2003. The carrying values of our liabilities were adjusted to their
present values at October 31, 2003. The terms "Predecessor" and "Predecessor
Company" refer to PGS and its subsidiaries for periods prior to and including
October 31, 2003. The terms "Successor" and "Successor Company" refer to PGS and
its subsidiaries for periods from and after November 1, 2003. The effects of the
completion of the reorganization plan and adjustments for fresh-start reporting
recorded as of October 31, 2003 are Predecessor Company transactions. All other
results of operations on November 1, 2003 are Successor Company transactions.

     The financial data presented below and in our consolidated financial
statements and related notes included in Item 18 of this annual report as of and
for the year ended December 31, 2001 have been

                                        5
<PAGE>

restated, as described in note 4 to our consolidated financial statements
included in Item 18 of this annual report and in "Operating and Financial Review
and Prospects -- Restatement of Previously Issued Audited Financial Statements"
in Item 5 of this annual report. The financial data presented below and in our
consolidated financial statements and related notes included in Item 18 of this
annual report differs in many respects from that which had previously been
reported as unaudited in the various earnings releases covering the periods
since December 31, 2000. In addition, in light of the restatements reflected in
the financial data presented below and in our consolidated financial statements
and related notes included in Item 18 of this annual report as of and for all
periods since January 1, 2001, you should not rely on financial statements that
we previously reported for periods prior to January 1, 2001.

     Pursuant to Item 3.A.1 of Form 20-F, selected financial data as of December
31, 2000 and 1999 and for each of the years in the two-year period ended
December 31, 2000 have been omitted because such information cannot be provided
on an audited or unaudited restated basis without unreasonable effort or
expense. We believe that providing such information would involve unreasonable
effort or expense because (1) the benefits of providing such information are
diminished by the fact that we adopted fresh start reporting for financial
statement purposes, effective November 1, 2003, as described above, (2) the
preparation of such restated consolidated financial statements would be
extremely time consuming and burdensome since our current independent auditors,
Ernst & Young AS, were not our independent auditors during that two-year period,
and (3) we identified significant adjustments to the beginning balances as of
January 1, 2001 that would be burdensome and expensive to allocate and to apply
consistently and with reasonable precision to the individual years 2000 and
1999.

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY                     PREDECESSOR COMPANY
                                        ----------------   ----------------------------------------------
                                        TWO MONTHS ENDED                       YEARS ENDED DECEMBER 31,
                                          DECEMBER 31,     TEN MONTHS ENDED   ---------------------------
                                              2003         OCTOBER 31, 2003       2002           2001
                                        ----------------   ----------------   ------------   ------------
                                                                                              (RESTATED)
                                                (IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
<S>                                     <C>                <C>                <C>            <C>
STATEMENT OF OPERATIONS DATA:
Revenues..............................    $   172,371        $    961,864     $  1,043,231   $    893,230
Operating profit (loss)...............         10,702               9,825         (488,609)        46,798
Reorganization items:
  Gain on debt discharge..............             --           1,253,851               --             --
  Fresh-start adoption................             --            (532,268)              --             --
  Cost of reorganization..............         (3,325)            (52,334)          (3,616)            --
Income (loss) from continuing
  operations before cumulative effect
  of change in accounting
  principles..........................         (9,818)            556,938         (809,903)      (140,125)
Net income (loss).....................         (9,953)            557,045       (1,174,678)      (172,479)
Basic and diluted income (loss) per
  share from continuing operations....    $     (0.49)       $       5.39     $      (7.84)  $      (1.36)
Basic and diluted net income (loss)
  per share...........................          (0.50)               5.39           (11.37)         (1.68)
Basic and diluted weighted average
  shares outstanding..................     20,000,000         103,345,987      103,345,987    102,768,283
CASH FLOW DATA:
Cash flows provided by operating
  activities..........................    $    58,346        $    188,676     $    293,007   $    118,078
Cash flows (used in) investing
  activities..........................        (25,089)            (69,732)        (274,497)      (220,516)
Cash flows provided by (used in)
  financing activities................        (21,983)           (116,624)          (6,034)        56,852
Capital expenditures..................         15,985              42,065           56,735        147,536
Investment in multi-client library....          9,461              81,142          151,590        174,028
</Table>

                                        6
<PAGE>

<Table>
<Caption>
                                                               SUCCESSOR    PREDECESSOR
                                                                COMPANY       COMPANY
                                                              -----------   ------------
                                                                     DECEMBER 31,
                                                              --------------------------
                                                                 2003           2002
                                                              -----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>           <C>
BALANCE SHEET DATA:
Total assets................................................  $1,997,360     $2,839,757
Multi-client library, net...................................     408,005        583,859
Total long-term debt and capital lease obligations..........   1,172,147      1,409,134
Guaranteed preferred beneficial interest in PGS junior
  subordinated debt securities..............................          --        142,322
Common stock................................................      85,714         71,089
Shareholders' equity (deficit)..............................     353,634       (192,254)
</Table>

RISK FACTORS

You should carefully consider the risks described below. If any of the following
risks actually occur, our business, financial condition or results of operations
could be materially adversely affected and the trading price of our securities
could decline significantly.

RISK FACTORS RELATING TO FINANCIAL REPORTING MATTERS

We have continuing issues regarding our internal controls.

     Our independent auditors have identified the following material weaknesses:

     - insufficient documentation of or adherence to accounting policies and
       procedures relating to significant financial statement accounts;

     - inadequate U.S. GAAP expertise;

     - inadequate quality of financial reporting and closing of the books
       process at the segment level;

     - insufficient quality of support for accounting books and records; and

     - insufficient supervision and review of control activities.

     The Public Company Accounting Oversight Board has defined a material
weakness as "a significant deficiency, or combination of significant
deficiencies, that results in more than a remote likelihood that a material
misstatement of the annual or interim statements will not be prevented or
detected." Accordingly, material weaknesses increase the risk that the financial
information we report in the future could contain material errors. In November
2004, our independent auditors completed a re-audit of our 2001 financial
statements under U.S. GAAP that resulted in restatements of our previously
reported shareholders' equity as of January 1, 2001 and of our previously
reported results of operations for the year ended December 31, 2001. While we
believe that we have made substantial progress in addressing these material
weaknesses as described in "Controls and Procedures" in Item 15 of this annual
report, the material weaknesses have not been eliminated.

     Despite the remedial steps we have taken, the existence of material
weaknesses may also make it more difficult to comply with the new rules
(including those under Section 404 of the Sarbanes-Oxley Act of 2002) on
providing management reports on internal control over financial reporting.
Unless we cure these material weaknesses, we will be unable to obtain an
attestation report from our independent auditors, beginning with our annual
report for 2005, as required by Sarbanes-Oxley Section 404.

     The continuation of these financial reporting and internal control matters
could have a negative impact on the market value of our securities.

                                        7
<PAGE>

Our adoption of "fresh start" reporting may make future financial statements
difficult to compare.

     As a result of the November 2003 consummation of our reorganization plan,
we are operating our business under a new capital structure. In addition, we
adopted, as of November 1, 2003, fresh start reporting in accordance with SOP
90-7. Because SOP 90-7 required us to reset our assets and liabilities to then
current fair values, our financial condition and results of operations after our
reorganization will not be comparable to the financial condition and results of
operations reflected in our historical financial statements for periods prior to
November 2003. This may make it difficult to assess our performance after the
reorganization compared with our historical performance prior to the
reorganization.

RISK FACTORS RELATING TO OUR INDEBTEDNESS AND OTHER OBLIGATIONS

Although we have emerged from Chapter 11, we still have significant
indebtedness.

     We have a relatively high level of indebtedness in relation to our capital
structure. Because of the level of our debt and other contractual obligations, a
substantial portion of our cash flow from operations must be dedicated to debt
service and payments of such obligations. To the extent we use cash flow for
debt service and for payment of such obligations, such cash flow will not be
available for capital investment or other purposes.

Our debt agreements may limit our flexibility in responding to changing market
conditions or in pursuing business opportunities.

     Our debt agreements contain provisions that restrict our ability, among
other things, to:

     - pay dividends or make other restricted payments;

     - incur debt above specified amounts;

     - create or permit to exist liens on our assets;

     - consolidate, merge or transfer all or substantially all of our assets;

     - sell assets for consideration other than cash or cash equivalents or
       without using the proceeds to reinvest in our businesses or to repay
       debt;

     - undergo a change of control without having an obligation to purchase all
       of our senior notes;

     - enter into certain transactions with affiliates; and

     - engage in certain sale and leaseback transactions.

     These restrictions may limit our flexibility in responding to changing
market conditions or in pursuing business opportunities that we believe would
have a positive effect on our business.

Potentially increased payments under vessel lease arrangements may adversely
affect our financial condition, future results of operations and liquidity.

     We have entered into vessel lease arrangements for five of our Ramform
design seismic vessels, our FPSO vessel Petrojarl Foinaven and the topsides of
our FPSO vessel Ramform Banff. The leases are all legally defeased because we
have made payments to independent third party banks in consideration for which
these banks have assumed liability to the lessors equal to basic rentals and
termination sum obligations. The lessors claim tax depreciation (capital
allowances) on the capital expenditures that were incurred for the acquisition
of the leased assets. The UK Inland Revenue ("Inland Revenue") has not signed
off on the lessors' claims to capital allowances related to our leases.

     We understand that the Inland Revenue has generally deferred signing off on
defeased leases (not just ours) pending the outcome of a case that has been
appealed to the House of Lords, the highest UK court of appeal. We expect a
decision from the House of Lords in late 2004. In that case, the Inland Revenue
is challenging capital allowances associated with a defeased lease. While we
believe that the lease transaction

                                        8
<PAGE>

and the lease structure involved in this case are qualitatively different than
those associated with our leases, if the House of Lords rules in favor of the
Inland Revenue's position, there is a high likelihood that the Inland Revenue
will also challenge other defeased leases.

     If the Inland Revenue does successfully challenge one or more of our lease
arrangements, we could be liable for increased rental payments to the lessors,
additional collateral/security for such increased rental payments and increased
termination sums that would apply on either a voluntary or default termination
of our lease arrangements. The lessors might seek to impose such additional
payments prior to a final resolution of any challenge of our leases by the
Inland Revenue, with any increased collateral/security and/or rental payments
released or rebated to us in the event that the challenge ultimately proves
unsuccessful.

     In the case noted above, while the Inland Revenue has challenged the
capital allowances, it has not proposed the manner in which the associated lease
should be treated and various alternative treatments exist. As a result, we
cannot give you any assurances about the manner in which our leases may be
treated or the amount of any additional liability we might incur if the Inland
Revenue is successful in challenging one or more of our leases. However, the
exposure could be very large.

     If we become liable for a substantial amount at some point in the future,
we may not have sources of liquidity that would be sufficient to permit us to
pay the entire amount of such a possible liability. As a result, we could be
required to seek additional sources of financing and possibly take other
measures such as reducing or delaying capital expenditures and/or selling
assets. We may not be able to take all of the actions necessary to meet these
potential additional obligations on satisfactory terms or at all. As a result,
if our leases were successfully challenged, it would likely have a material
adverse affect on our financial condition, future results of operations and
liquidity. Please read "Financial Information -- Legal Proceedings -- UK Legal
Proceedings Involving Third Parties" in Item 8, "Operating and Financial Review
and Prospects -- Liquidity and Capital Resources -- UK Leases" in Item 5 and
notes 2 and 19 of the notes to our consolidated financial statements in Item 18
of this annual report for additional information relating to these UK lease
matters.

Our ability to obtain additional financing or to refinance our indebtedness
could be restricted.

     As of October 31, 2004, our long-term unsecured indebtedness was not rated
by a national credit rating agency. As long as we have no published credit
rating, or if we were to have a relatively low, non-investment grade credit
rating, our ability to access the debt capital markets could be restricted and
our cost of raising capital would likely be increased. Such situation could
restrict our ability to obtain additional financing or to refinance our existing
indebtedness, or to do so on satisfactory terms.

     The continued existence of material weaknesses as described above under
"Risk Factors -- Risk Factors Relating to Financial Reporting Matters -- We have
continuing issues regarding our internal controls" could similarly result in
restrictions on our ability to obtain financing, or to do so on satisfactory
terms.

     In addition, the continued existence of the uncertainty relating to our UK
leases as described above under "-- Potentially increased payments under vessel
lease arrangements may adversely affect our financial condition, future results
of operations and liquidity" could restrict our ability to obtain additional
financing, or to do so on satisfactory terms.

RISK FACTORS RELATING TO OUR BUSINESS OPERATIONS GENERALLY

Our business could be adversely affected if demand for our services from oil and
natural gas companies decreases.

     Our geophysical and offshore production businesses depend substantially
upon exploration, development and production spending by oil and natural gas
companies. Capital expenditures, and in particular exploration and development
expenditures, by oil and natural gas companies have tended in the past to follow
trends in the prices of oil and natural gas, which have fluctuated widely in
recent years. Lower oil
                                        9
<PAGE>

and natural gas prices, actual or projected, may reduce the level of that
spending, 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 significant investments
in vessels, in processing, seismic and other equipment and in acquiring and
developing oil and natural gas reserves. We also incur relatively high fixed
costs in our operations. If we cannot keep our vessels and other equipment
utilized at relatively high levels, due to reduced demand, weather
interruptions, equipment failure, technical difficulties, labor unrest or other
causes, we could incur significant operating losses.

Our future revenues may fluctuate significantly from period to period.

     Our future revenues may fluctuate significantly from quarter to quarter and
from year to year as a result of various factors including the following:

     - levels of activity planned by our customers;

     - the timing of offshore lease sales 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;

     - fluctuating oil and natural gas prices, which impact both customer demand
       for our geophysical and offshore production services and the revenues we
       receive in our production services business and from selling oil and
       natural gas in our oil and natural gas business;

     - 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 frequently 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 maintain competitive
technologies. Technology changes rapidly, and new and enhanced products and
services are frequently introduced in our markets, particularly in the
geophysical services (including seismic data processing) business. Our success
depends to a significant extent on our ability to develop and produce new and
enhanced products and services on a cost-effective and timely basis in
accordance with industry demands. While we commit resources to research and
development, we may encounter resource constraints or technical or other
difficulties that could delay introduction of new and enhanced products and
services in the future. In addition, continuing development of new products and
services inherently carries the risk of obsolescence of older products and
services. New and enhanced products and services, if introduced, may not gain
market acceptance or may be adversely 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 and regulations, 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;

                                        10
<PAGE>

     - occupational health and safety; and

     - the protection of the environment.

     We and our customers are required to invest financial and managerial
resources to comply with these laws and regulations. Because these laws and
regulations and our business change from time to time, we cannot predict the
future costs of complying with these laws and regulations, and our expenditures
could increase materially in the future. Modification of existing laws or
regulations or adoption of new laws or regulations limiting exploration or
production activities by oil and natural gas companies or imposing more
stringent restrictions on geophysical or hydrocarbon production-related
operations could adversely affect us by increasing our operating costs and/or
reducing the demand for our services.

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 operations outside the
United States and Norway. These operations are subject in varying degrees to
risks inherent in doing business abroad including risks of war, terrorist
activities, political, civil or labor disturbances and embargoes. Our operations
are also subject to various risks related to government activities, including:

     - 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 disruption of operations from labor and political disturbances;

     - 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, production services and
oil and natural gas production businesses.

     Our seismic data acquisition, offshore production services and oil and
natural gas production activities often take place under extreme weather and
other hazardous conditions. In particular, a substantial portion of our
operations are subject to perils that are customary for marine operations,
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 or equipment, personal injury and
property damage, suspension of operations or environmental damage. In addition,
our operations involve risks of a technical and operational nature due to the
complex systems that we utilize. If any of these events occur, our business
could be interrupted and we could incur significant liabilities. In addition,
many factors may curtail, delay or cancel our oil and natural gas development
and production activities, including pressure or irregularities in geological
formations, shortages of or delays in obtaining equipment and qualified
personnel, equipment failures or accidents, adverse weather conditions,
reductions in oil and natural gas prices, and limitations in the market for oil
and natural gas.

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 the destruction of or damage to our
seismic and floating production, storage and offloading vessels and equipment in
amounts that we consider adequate, such insurance coverage is subject to
exclusions for losses due to war risks and terrorists acts. In addition, we may
not be able to maintain

                                        11
<PAGE>

adequate insurance for our vessels and equipment in the future or do so at rates
that we consider reasonable. We do not maintain insurance to protect against
business interruptions.

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 devaluations could have a
material impact on our results of operations from time to time. Historically,
most of our revenue and operating expenses have been generated in U.S. dollars,
NOK and British pounds. Although we periodically undertake limited hedging
activities in an attempt to reduce certain currency fluctuation risks, these
activities do not provide complete protection from currency-related losses. In
addition, in some circumstances our hedging activities can require us to make
cash outlays. Finally, our ability to enter into currency hedging transactions
may be limited because of our lack of, or by our having a low, 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 are obtained
through a competitive bidding process. While no single company competes with us
in all of our business segments, we are subject to intense competition from
large, international companies and smaller, local companies in each of our
businesses. Some of our competitors have greater financial and other resources
than us and may be better positioned to withstand and adjust more quickly to
volatile market conditions and changes in government regulations. We also face
competition from new low-cost competitors in various geographic areas,
particularly in the onshore seismic market.

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 at what price we will be able to sell the data.

     We invest significant amounts in acquiring and processing seismic data that
we own, which we call multi-client data. By making 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 if any
       material adverse change occurred in the general prospects for oil and
       natural gas exploration, development and production activities in the
       areas where we acquire multi-client data.

In particular, we own a significant amount of multi-client data offshore Brazil.
As of December 31, 2003, the carrying value of our multi-client data offshore
Brazil was $164.9 million. A slowdown in sales in this region could have an
adverse impact on our multi-client data sales. If any of these risks occurs, the
value of our multi-client data could be impaired and we would be required to
recognize impairment charges. In the past, we have incurred substantial
impairment charges related to our multi-client data.

     Our future multi-client data sales are uncertain and depend on a variety of
factors, many of which are beyond our control. In addition, the timing of these
sales can vary greatly from period to period. Technological or regulatory
changes or other developments also could reduce the value of 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 library has a
significant effect on our results of operations. We amortize the capitalized
cost of our multi-client data library based principally on the relationship of
actual data sales for the relevant data to our estimates of total, including
future, sales of

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<PAGE>

data. Our sales estimates are inherently imprecise and may vary from period to
period depending upon market developments and our expectations. Changes in the
amounts and timing of data sales may result in impairment charges or changes in
our amortization expense, which will affect our results of operations.

     Substantial changes in amortization rates can have a significant effect on
our results of operations.

We perform a substantial 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 turnkey contracts
where our work is delivered at a predetermined and fixed price. In submitting a
bid on a turnkey contract, we estimate our costs associated with the project.
However, our actual costs can vary from our estimated costs because of changes
in operating conditions (including weather, fishing activity, interference from
other seismic vessels and other operating disturbances) and equipment
productivity, among others. As a result, we may experience reduced profitability
or losses on projects if our bids on turnkey contracts are too low and/or actual
costs exceed estimated costs.

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 contracts involve 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;

     - 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 PRIMARILY TO OUR OIL AND NATURAL GAS PRODUCTION ACTIVITIES

Developing and producing oil and natural gas are high-risk activities with many
uncertainties that could adversely affect our results of operations.

     Our oil and natural gas development and production activities are subject
to numerous risks beyond our control, including the risk that drilling will not
result in commercially viable oil or natural gas production. Our decisions to
acquire, develop or otherwise exploit prospects or properties will depend in
part on the evaluation of data obtained through geophysical and geological
analyses, production data and engineering studies, the results of which are
often inconclusive or subject to varying interpretations.

The oil and natural gas business involves many uncertainties and operating risks
that can cause substantial losses.

     Our oil and natural gas operations involve a variety of operating risks,
including:

     - equipment failures and accidents;

     - blow-outs and surface cratering and fires and explosions;

     - natural disasters;

                                        13
<PAGE>

     - abnormally pressured formations; and

     - environmental hazards, such as uncontrollable flows of oil, natural gas,
       well fluids, toxic gases or other pollutants into the environment.

     If we experience any of these problems, it could affect well bores and
production facilities, which could adversely affect our ability to conduct our
oil and natural gas operations. We could incur substantial liabilities and
losses as a result of:

     - injury or loss of life;

     - severe damage to and destruction of property, natural resources and
       equipment;

     - pollution and other environmental damage;

     - suspension of our oil and natural gas operations; and

     - repairs to resume operations.

Estimates of our oil and natural gas reserves, future cash flows and abandonment
costs depend on many assumptions that may prove to be inaccurate. Any material
inaccuracies in these estimates or underlying assumptions will materially affect
the quantities and present value of our reserves and could materially affect our
results of operations.

     Reserve estimation is a subjective process that involves estimating volumes
to be recovered from underground accumulations of oil and natural gas that
cannot be directly measured. Reserve estimation is complex and inherently
imprecise and requires interpretations of available technical data and many
assumptions, including assumptions relating to economic factors. Although we
employ independent engineers to review our estimates of reserves, any
significant inaccuracies in these interpretations or assumptions could
materially affect the estimated quantities and present value of our reserves.

     In order to prepare our reserve estimates, we must estimate, project or
assume, among other things:

     - the quantities of oil and natural gas that may be ultimately produced;

     - the timing of the production;

     - the revenues associated with and the prices received for the proved
       reserves that are produced;

     - the production and operating costs incurred; and

     - the amount and timing of future development expenditures.

Actual future production, the timing of such production, oil and natural gas
prices received for our production, production and operating costs we incur and
the amount and timing of our development expenditures most likely will vary from
our estimates. We will likely adjust estimates of our proved reserves from time
to time to reflect production history, results of development, prevailing oil
and natural gas prices and other factors, many of which are beyond our control.

     If costs of abandonment for our oil and natural gas reservoirs and
production equipment are materially greater than our estimates, they could have
an adverse effect on results of operations.

A substantial or extended decline in oil and natural gas prices may adversely
affect our oil and natural gas business and results of operations.

     The price we receive for our oil and natural gas production heavily
influences our revenue for our oil and natural gas segment. The prices we
receive for our production depend on numerous factors that are beyond our
control. Lower oil and natural gas prices may not only decrease our revenues on
a per unit basis, but also may reduce the amount of oil and natural gas that we
can produce economically.

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<PAGE>

We may not be able to find, develop or acquire properties to maintain or
increase our levels of proved reserves.

     Our future oil and natural gas production is highly dependent upon our
level of success in finding, developing and acquiring reserves that are
economically recoverable. As our reserves decline from production, we must incur
significant capital expenditures if we desire to maintain production levels. We
may not be able to identify, develop or complete the acquisition of properties
with sufficient proved reserves to maintain or increase our reserve levels. In
addition, substantially all of our proved reserves are located on the Norwegian
Continental Shelf, a maturing resource province. If our development efforts in
the NCS are unsuccessful, our proved reserves will decline unless we acquire
additional properties. The availability of properties for acquisition depends
largely on the divesting practices of oil and natural gas companies, commodity
prices, general economic conditions and other factors that we cannot control. A
substantial decrease in the availability of proved oil and natural gas
properties in the NCS and elsewhere, or a substantial increase in the cost to
acquire properties in the NCS and elsewhere, could adversely affect our ability
to replace our reserves. A substantial increase in our lifting cost may
adversely affect our oil and natural gas business and results of operations.

Substantially all of our oil and natural gas production is derived from assets
that are concentrated in a geographic area under one production license.

     Currently, substantially all of our production is derived from activities
carried out by our subsidiary, Pertra, on the NCS under a license from the
Norwegian Ministry of Petroleum and Energy. If oil and natural gas operations in
that area were adversely affected in any way, our production levels could be
materially and adversely impacted. In addition, if our license were to be
terminated for any reason, our revenue and cash flow from our oil and natural
gas operations would be adversely affected.

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 in many
jurisdictions around the world with increasingly complex tax laws. The amounts
of taxes we pay in these jurisdictions could increase substantially as a result
of changes in these laws or their interpretations by the relevant taxing
authorities, which could have a material adverse effect on our liquidity and
results of operations. In addition, those authorities could review our tax
returns and impose additional taxes and penalties, which could be material. We
have an issue pending with the Norwegian Central Tax Office ("CTO") for 2002
relating to two of our subsidiaries that withdrew from the Norwegian tonnage tax
regime. If the CTO position is upheld, we estimate that taxes payable for 2002,
without considering mitigating actions, could increase by up to $24 million.

     In addition, we have exposure relating to taxes as described above under
"Risk Factors Relating to Our Indebtedness and Other Obligations -- Potentially
increased payments under vessel lease arrangements may adversely affect our
financial condition, future results of operations and liquidity."

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 substantially all of our
current directors and executive officers reside outside the United States. All
or a substantial portion of the assets of these persons and our company are
located outside the United 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

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<PAGE>

     - 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.

Because our ADSs currently do not trade on a national exchange, you may have
difficulty trading in our ADSs.

     Our ADSs trade on the over-the-counter Pink Sheets under the symbol
"PGEOY." Trades in our ADSs over-the-counter and through quotation on the Pink
Sheets may not be executed as quickly as when the securities were listed on a
national exchange. As a result, an investment in our ADSs may now be exposed to
a greater risk of loss and limited liquidity. Although we are using reasonable
commercial efforts to list our ADSs on a national exchange as soon as
practicable, taking into account relevant United States listing requirements, we
cannot provide assurance that we will be able to list our ADSs on a national
securities exchange or that a market for our securities will develop and be
maintained. Without a developed market, a holder of our securities may have
difficulty disposing of them. Even if a market for PGS securities develops, we
cannot provide any assurance about the degree of price volatility in any such
market that does develop.

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<PAGE>

ITEM 4. INFORMATION ON THE COMPANY

HISTORY AND DEVELOPMENT OF THE COMPANY

  ORGANIZATION

     Petroleum Geo-Services ASA is a public limited liability company
established under the laws of the Kingdom of Norway in 1991. We are organized as
a holding company that owns subsidiary companies. Our subsidiary companies
conduct substantially all of our business. Unless we inform you otherwise or the
context indicates otherwise, references to us in this annual report are to
Petroleum Geo-Services ASA, its predecessors and its majority-owned
subsidiaries. We maintain our headquarters and executive offices at Lysaker,
Norway (Strandveien 4, N-1366, telephone: +47-67-52-6400). Our registration
number in the Norwegian Company Registry is 916235291. Our agent in the United
States is CT Corporation System, 1633 Broadway, New York, New York 10019.

  WHO WE ARE

     We are a technologically focused oilfield service company principally
involved in providing geophysical services worldwide and providing floating
production services in the North Sea. Globally, we provide a broad range of
geophysical and reservoir services, including seismic data acquisition,
processing and interpretation and field evaluation. In the North Sea, we own and
operate four floating production, storage and offloading ("FPSO") units. We also
own a small oil and natural gas company that produces oil and natural gas from a
license on the Norwegian Continental Shelf ("NCS").

     In February 2003, we revised our organizational structure. Prior to
February 2003, we were organized and managed as two business segments,
geophysical and production. Due to the increased size and importance of certain
businesses within these segments and in order to improve our management
structure, we now manage our overall business in four 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;

     - Production, which owns and operates four harsh environment FPSO units in
       the North Sea; and

     - Pertra, a small oil and natural gas company that owns 70% of and is the
       operator for Production License 038 on the NCS and also owns
       participating interests in two additional NCS licenses in areas that do
       not have current production.

We manage our Marine Geophysical segment from Lysaker, Norway, our Onshore
segment from Houston, Texas, and our Production segment and Pertra from
Trondheim, Norway.

  HISTORICAL DEVELOPMENT

     The primary milestones in our historical development include the following:

     - January 1991:  Company is 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

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<PAGE>

     - 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

     - November 2001:  Announcement of business combination transaction with
       Veritas DGC (terminated in July 2002)

     - August 2002:  Acquisition of 70% ownership in and operatorship of
       Production License 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 interim
       Chief Financial Officer

     - December 2002:  Sale of Production Services subsidiary to Petrofac Ltd.

     - February 2003:  Sale of Atlantis subsidiary to Sinochem

     - June 2003:  Announcement of agreement in principle for proposed financial
       restructuring

     - 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

2003 DEVELOPMENTS

  GENERAL BUSINESS DEVELOPMENTS

     Although 2003 was a period of financial difficulty and uncertainty, we
believe that we took important steps to maintain and further develop our
operating performance and to better position ourselves in the business segments
in which we operate. Our primary business achievements in 2003 include:

     - improving our cost structure through execution of our cost reduction
       program announced early in 2003;

     - improving our position in the seismic contract market;

     - extending the expected contract duration for three of our FPSO units as a
       result of field reserve upgrades and contract amendments;

     - increasing our oil and natural gas reserves in Pertra resulting from a
       combination of acquisition and application of seismic data, reservoir
       modeling and an enhanced oil recovery drilling program;

     - strong operating regularity and uptime in our businesses; and

     - strong safety performance.

  FINANCIAL RESTRUCTURING

     In the late 1990s, we, like other geophysical companies, invested
significantly in increased seismic acquisition capacity to meet expected growth
in oil and natural gas exploration and production activities. During this
period, we also invested heavily in our multi-client library, in our FPSO vessel
Ramform Banff and in our oil and natural gas subsidiary Atlantis. To finance
these investments, we incurred substantial amounts of debt that required
increasing amounts of our cash flow to be devoted to debt service. The expected
growth in demand for our services did not materialize, however, and the cash
flow generated by many of our investments proved to be significantly lower than
expected.

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<PAGE>

     In 2002, it became clear that a comprehensive financial restructuring was
crucial to our long-term viability and to provide a sustainable capital
structure going forward. In late 2002 we engaged financial advisors and began
discussions with representatives of our banks and bondholders with a view to
developing a comprehensive financial restructuring.

     On June 18, 2003, we announced that we had reached an agreement in
principle with a majority of our banks and bondholders, a significant holder of
our trust preferred securities, and a group of our largest shareholders to
undertake a financial restructuring of our total debt through a conversion of
our existing bank and bond debt and trust preferred securities into new debt and
a majority of our post-restructuring equity.

     On July 29, 2003, in order to implement the proposed restructuring plan, we
voluntarily filed a petition for protection under Chapter 11 of the U.S.
Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New
York and submitted a plan of reorganization and a disclosure statement. The case
was filed only for our parent company and did not involve any of our operating
subsidiaries.

     The reorganization plan became effective and was substantially consummated
on November 5, 2003, at which time we emerged from Chapter 11 reorganization.
Under the plan, our then-existing bank debt and outstanding senior notes were
canceled in exchange for a combination of new senior notes, new ordinary shares
and the right to receive cash. For additional information about our
restructuring, please read "Operating and Financial Review and
Prospects -- Financial Restructuring" in Item 5 of this annual report and note 3
of the notes to our consolidated financial statements included in Item 18 of
this annual report.

  SALES OF PRODUCTION SERVICES, ATLANTIS AND TIGRESS SUBSIDIARIES

     In December 2002, we sold our Production Services (formerly Atlantic Power
Group) subsidiary to Petrofac Ltd. for approximately $20.2 million in cash and
the right to receive additional amounts of up to $15.0 million if various
contingencies occur.

     In February 2003, we sold our Atlantis oil and natural gas subsidiary to
China National Chemicals Import and Export Corporation, or "Sinochem," for a
combination of $48.6 million in cash, the reimbursement of $10.6 million of
expenditures and the right to receive additional future payments of up to $25.0
million if certain contingent events occur.

     In December 2003, we sold our non-strategic software subsidiary, PGS
Tigress (UK) Ltd., for a deferred compensation payable in 2004 and 2007 of $1.8
million in the aggregate.

OUR BUSINESS PRIORITIES

     Following our financial reorganization in 2003, our strategic business
focuses have included:

     - improving cash flow from our existing operations;

     - achieving further improvements in safety, operating regularity and cost;

     - realizing business synergies between our different operations;

     - identifying and pursuing attractive industry restructuring opportunities;
       and

     - strengthening internal controls, corporate governance and human resource
       capabilities.

OUR GEOPHYSICAL SERVICES

  OVERVIEW

     Our geophysical services business constitutes one of the major global
players 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 and natural gas companies to help them find oil
and natural gas and to determine the size and structure of known oil and natural
gas reservoirs. In our seismic
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<PAGE>

projects, we are involved in planning the seismic surveys and acquiring and
processing the seismic data. Oil and natural gas companies use this information
in evaluating whether to acquire new leases or licenses in areas with potential
accumulations of oil and natural gas, in selecting drilling locations, in
modeling oil and natural gas reservoir areas and in managing producing
reservoirs. Oil and natural gas companies use 4D or time lapse surveys, which
are surveys produced by the repetition of identical 3D surveys over time, to
assist in their evaluation of subsurface geophysical conditions that change over
time due to the depletion and production of reservoir fluids. This evaluation
provides for more efficient production of the reservoir and the possible
extension of the reservoir's useful life. We use our High Density
3D -- HD3D(SM) -- technology to acquire 3D data with higher trace densities,
giving improved resolution of the subsurface and higher quality images of the
reservoirs.

     We acquire seismic data both on an exclusive contract basis for our
customers and on our own behalf as multi-client data for licensing from time to
time to multiple customers on a non-exclusive basis. In some of our projects, we
share interests in the revenue from the sales of the multi-client data with
third parties. During 2003, we made a deliberate shift in the utilization of our
data acquisition capacity from multi-client to the contract market such that a
substantial majority of our capacity was used in the contract market.

     We manage our geophysical services through two segments:

     - Marine Geophysical, which consists of both streamer and seafloor 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.

     During 2003, we:

     - made significant reductions in marine seismic staff;

     - reduced vessel downtime;

     - increased our average productivity per vessel; and

     - significantly reduced capital expenditures in Onshore.

  OUR STRATEGIES FOR GEOPHYSICAL SERVICES

     Our principal strategies for our geophysical services include:

     - capitalizing on our strong cost position and operating performance;

     - focusing on the contract market;

     - investing in multi-client data in a financially disciplined manner that
       complements our contract data acquisition activities;

     - increasing our focus on the less volatile reservoir and production
       related seismic market through application of our HD3D(SM) techniques, 4D
       acquisition and multi-component acquisition; and

     - identifying and pursuing attractive industry restructuring opportunities.

     Over the past several years, we have invested heavily in our multi-client
seismic data library and in high technology acquisition equipment, including:

     - our Ramform seismic vessels and deep water seafloor FOURcE(SM)
       acquisition systems;

     - 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

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<PAGE>

     - state-of-the-art technology in our onshore seismic data acquisition
       equipment to enable efficient acquisition of high quality seismic data in
       varied terrain.

     We believe that our main competitive strengths within our geophysical
services business include:

     - 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 large surveys;

     - high channel count for onshore operations; and

     - our highly experienced work force.

  GEOGRAPHIC AREAS OF OPERATION

     We have divided our Marine Geophysical business in three primary areas of
operations:

     - North and South America;

     - Europe, Africa and the Middle East; and

     - Asia Pacific.

     We have divided our Onshore geophysical business in three primary 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 natural gas
exploration or production areas around the world, including:

     - offshore 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;

     - West Africa;

     - 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 a contract basis, our
customers direct the scope and extent of the survey and retain ownership of the
data obtained. Contracts for seismic data

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<PAGE>

acquisition, which are generally awarded on a competitive bid basis, often are
turnkey contracts. Under this turnkey method, the customers pay based upon the
number of seismic lines or square kilometers of seismic data collected and we
often bear some or all of the risk of business interruption, due to causes
beyond our control such as, among others, weather and permitting.

     During 2003, we increased our emphasis on acquiring seismic data on a
contract basis. We performed contract operations during 2003 in the North Sea;
offshore and onshore Mexico; offshore West Africa, Australia, China and other
countries in the Asia Pacific region; offshore and onshore South America;
offshore Canada; onshore in the U.S. mid-continent, Rocky Mountains, Gulf Coast
and Alaskan North Slope regions and offshore and onshore in Central Asia and the
Middle East.

     Multi-Client Operations.  From the perspective of an oil and natural gas
company, licensing multi-client seismic data on a non-exclusive basis is
typically less expensive on a per unit basis than acquiring the seismic data on
an exclusive basis. From our perspective, multi-client seismic data is more cost
effective to acquire and may be sold a number of times to different customers
over a period of years. As a result, multi-client seismic data has the potential
to be more profitable than contract data. However, when we acquire multi-client
seismic data we assume the risk that future sales may not cover the cost of
acquiring and processing such seismic data. Obtaining prefunding for a portion
of these costs reduces this risk. The level of prefunding we require before
initiating a multi-client seismic survey is determined by evaluating various
factors affecting the sales potential of each survey. These factors include:

     - the existence, quality and age of any seismic data that may already exist
       in the area;

     - the amount of leased acreage in the area;

     - 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 most of the
major oil and natural gas basins of the world, including the Gulf of Mexico, the
North Sea, offshore West Africa, offshore Brazil and the Asia Pacific region.
Our onshore library is entirely in North America. We continue to build and
market our multi-client data library, including seafloor and onshore data, but
we also intend to acquire multi-client data in additional geographic areas from
time to time. During 2003, compared to earlier years, we substantially reduced
the amount we invested in new multi-client data.

     In our multi-client operations, we make initial sales of the data prior to
project completion, which we refer to as prefunding sales, and we refer to all
further sales as late sales. We make a substantial portion of these late sales
in connection with acreage license round activity in those regions where we have
a data library. Typically, customers are required to pay an amount for access to
the data and additional amounts, or uplift fees, for successful concession award
or sometimes execution of a production sharing or similar contract. The timing
and regularity of such license round activity varies considerably depending upon
a number of factors, including in particular the geopolitical stability of the
region in question. As a result, the actual timing of late sales can be
difficult to forecast accurately, with potentially significant revenue swings
from quarter to quarter and from year to year.

     We attempt to protect our multi-client seismic data from misuse by
customers primarily through contractual provisions that permit the use of the
data only by that particular customer on a nontransferable basis. Such
provisions can be effective only if misuse of the data by customers or third
parties can be detected and if our rights can be enforced through legal action.

     Our multi-client data is marketed primarily through our own sales
organization. In prior years, we also marketed the data through various
agreements with third parties, most of which have been terminated.

                                        22
<PAGE>

  DATA PROCESSING

     We provide seismic data processing services for our own seismic data
acquisition operations and for third parties. Generally, we compete for data
processing contracts on a competitive bid basis. These contracts generally
provide for the customer to pay a flat fee per square kilometer processed for a
prescribed set of processing procedures. Additional procedures may be quoted
separately and are often added during the course of a project.

     We reorganized our data processing division during 2003 to be part of our
regional marine business unit. Technical support, research and development and
computer operations continue to be provided on a global basis. As of October 31,
2004, we operated nine land-based seismic data processing centers, with the
largest centers being located in Houston, Texas, U.S.; London, England; Lysaker,
Norway; Cairo, Egypt; and Perth, Australia. The largest seismic processing
centers utilize computer resources organized in a global computer resource
organization consisting of three major computer centers located in Houston,
London and Perth. These three centers are inter-connected through high capacity
network links. In addition, some of our marine seismic crews have the capability
to perform data processing.

     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;

     - 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 the most advanced
marine seismic data acquisition fleets in the world. As of October 31, 2004, we
had a total of ten 3D marine seismic streamer crews operating ten seismic
vessels, and we had one seafloor seismic crew operating a total of three
vessels.

     Seafloor Seismic Acquisition.  We use seafloor seismic acquisition in areas
where conventional streamer acquisition operations are not possible or
economically feasible due to access limitations from shallow water or
obstructions. Seafloor seismic acquisition is also used in areas where
conventional streamer acquisition would not meet the desired geophysical
objectives. As of October 31, 2004, we operated one seafloor seismic crew
consisting of one recording vessel, one source vessel and one cable laying
vessel.

     In our multi-component seafloor seismic operations, we record both
hydrophone and geophone data simultaneously. Processing the data with PGS'
proprietary software allows for enhanced reservoir imaging and characterization,
which improves chances of discovery success at the exploration stage,
information relating to the size of and reserve estimates for reservoirs at the
appraisal and development stages, decision-making regarding production strategy
and the chances of maximizing total reserve recovery at the production stage.

     Vessel Fleet and Crews.  We acquire marine seismic data using seismic crews
on both owned and chartered vessels that have been constructed or modified to
our specifications and outfitted with a complement of data acquisition,
recording, navigation and communications equipment. Our crews direct the
positioning of a vessel using sophisticated navigation equipment, deploy and
retrieve streamers, cables, receivers and energy sources, and operate all of the
seismic systems. Our seismic crews do not operate the vessels. The vessel
maritime crews are employees of either the owner of the chartered vessels or a
contract operator for our vessels.

                                        23
<PAGE>

     Most of our seismic vessels have an equipment complement consisting 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 airgun array
       firing system that activates the acoustic energy source.

     For the seafloor seismic operations, the Ocean Explorer and the Bergen
Surveyor each has a dynamic positioning system and recording instrumentation
that permits the recording of data from up to 48 kilometers of ocean bottom
cables. These vessels also have equipment to deploy and recover cables
automatically.

     We provide in the following table information as of October 31, 2004 about
our marine seismic data acquisition vessels.

<Table>
<Caption>
                                                                                   MAXIMUM
                                                                                  STREAMERS
                                                                                   DEPLOYED
                                                TOTAL    TOTAL    LONG-LENGTH      (THROUGH      OWNED OR
                                YEAR RIGGED/    LENGTH    BEAM      STREAMER     DECEMBER 31,    CHARTER
VESSEL NAME                       CONVERTED     (FEET)   (FEET)    CAPABILITY       2003)       EXPIRATION
-----------                     -------------   ------   ------   ------------   ------------   ----------
<S>                             <C>             <C>      <C>      <C>            <C>            <C>
3D SEISMIC VESSELS:
Ramform Explorer..............  1995            270      130           12              8            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             10          2023(1)
Ramform Victory...............  1999            284      130           20             16          2024(1)
Ramform Vanguard..............  1999            284      130           20             10          2024(1)
Atlantic Explorer.............  1994            300       58            6              6            Owned
American Explorer.............  1994            306       59            8              8            Owned
Nordic Explorer...............  1993            209       54            6              6            Owned
Orient Explorer...............  1995/96         246       49            4              4             2004
SEAFLOOR SEISMIC VESSELS:
Falcon Explorer...............  1997            266       53          N/A            N/A             2005
Bergen Surveyor...............  1997            217       48          N/A            N/A          2005(2)
Ocean Explorer................  1993/95         269       59          N/A            N/A            Owned
</Table>

---------------

(1) We have UK lease arrangements for each of the Ramform Valiant, the Ramform
    Viking, the Ramform Victory and the Ramform Vanguard and a conditional sale
    and leaseback arrangement with respect to 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 19 of the notes to our consolidated
    financial statements included in Item 18 of this annual report.

(2) We can terminate the charter for this vessel on three months' notice.

     Competition in Our Geophysical Businesses.  The seismic data acquisition
and processing businesses are very competitive worldwide for both the contract
market and the multi-client market. We compete for available seismic surveys
based on a number of factors, including technology, price, performance,
dependability, crew availability, turnaround time and processing capacity
availability. Our largest competitors on a global basis are WesternGeco, a joint
venture between the seismic units of Schlumberger

                                        24
<PAGE>

Limited and Baker Hughes Incorporated, Compagnie Generale de Geophysique, S.A.
and Veritas DGC Inc.

     All of our major competitors in the seismic business both acquire and
process 3D seismic data. Our processing operations compete primarily with
WesternGeco, Compagnie Generale de Geophysique and Veritas DGC for time
processing contracts. For depth imaging and other advanced processing
applications, we also compete with several smaller processing companies. We
compete for time processing contracts based primarily on price and technology,
but processing capacity, turnaround time and processing center location are also
important factors.

  OUR ONSHORE SEGMENT

     Our Onshore segment consists of all our seismic acquisition operations on
land and in very shallow water and transition zones, including the onshore
multi-client library. We conduct contract onshore seismic acquisition throughout
the world. Our onshore multi-client library is entirely in the United States.
During 2003, we conducted seismic acquisition operations in the United States
(Gulf Coast, mid-continent, Rocky Mountains and Alaska), Mexico, Ecuador, Saudi
Arabia and Bangladesh. During 2004, active crew counts have ranged from four to
eight, operating in various areas including Mexico, the United States,
Bangladesh, Ecuador and Bolivia. As of October 31, 2004, we had five crews
conducting activities in Mexico, the United States and Canada. We also have
environmental specific operating equipment in Alaska and in the Middle East. We
are pursuing additional contract opportunities in Mexico, South America, Africa,
Central Asia, the United States and the Middle East and are expanding our
multi-client onshore library in the U.S. mid-continent.

     In the market for onshore seismic services, we are a medium sized operator
among a large number of regional and global competitors. Competition in the
Onshore segment is intense and varies from region to region. In particular, we
have seen increased competition from Chinese operators who have aggressively
expanded their global presence. We believe that we can remain competitive by
capitalizing on our project execution and management skills and by continuing to
provide a high quality technical product. The majority of our recording
equipment pool is relatively uniform, facilitating changing crew counts and
channel counts on any specific crew as the market dictates.

OUR PRODUCTION SEGMENT

  OVERVIEW

     We are one of the largest operators of FPSO vessels in the North Sea,
measured by production capacity and number of vessels. Through our Production
segment, we own and operate four FPSO vessels with a combined production
capacity of 339,000 barrels of oil per day and a crude oil storage capacity of
one million barrels. All four of our FPSOs, the Ramform Banff, Petrojarl I,
Petrojarl Foinaven and Petrojarl Varg, are double hulled, rated for harsh
environments and capable of working in deepwater fields.

     We believe that our fleet of FPSO vessels is one of the most
technologically advanced in the industry. We have experience operating in some
of the industry's most demanding environments in the North Sea and the
continental shelf of the Atlantic Ocean. During 2003, we improved or extended
three of our FPSO contracts as follows:

     - Petrojarl Varg contract expected to extend beyond 2006 based on
       additional reserves and expected future development;

     - Petrojarl I contract estimated to extend until 2007 based on additional
       reserves; and

     - Ramform Banff contract amended with improved economic terms.

     An FPSO system is a ship-based type of mobile production unit that
produces, processes, stores and offloads oil and processes, reinjects or exports
gas from offshore fields with widely differing production characteristics, sizes
and water depths. The selection of a particular mobile production unit from
among the several types of readily movable offshore production systems depends
on several factors, including
                                        25
<PAGE>

overall reservoir and environmental characteristics of the field to be
developed, availability of transportation infrastructure and financial and
schedule constraints. FPSO systems typically perform the same function as fixed
offshore platforms in the offshore production of oil and natural gas, with the
exceptions of drilling and heavy well maintenance. However, FPSO systems
generally provide a number of advantages over fixed platforms, including:

     - 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:

     - capitalizing on our strong North Sea floating production operations;

     - maximizing the value of our existing contracts through maintaining a high
       level of operational performance, through incentive structures and
       through pursuing opportunities to extend the contracts;

     - capturing the potential upside from reservoir exposure utilizing in-house
       competence; and

     - pursuing growth opportunities through offering solutions for new
       developments.

We believe a number of redeployment opportunities exist in the North Sea,
particularly on the Norwegian Continental Shelf, where we currently operate two
vessels. We also intend to continue to evaluate opportunities in other regions.

  THE FPSO MARKET

     The market for production services differs fundamentally from the
geophysical market. Offshore production generally takes place a relatively long
time after exploration drilling has been completed. As a result, oil and natural
gas companies typically make production-related decisions based on different
financial parameters than those used for decisions relating to seismic or
drilling activities. As offshore hydrocarbon basins around the world in general
have matured, oil and natural gas companies in a number of oil producing areas
have increasingly focused on the development of smaller fields with relatively
smaller or uncertain reservoir estimates and/or shorter expected producing
lives. For development of these smaller fields to be profitable, the oil and
natural gas companies must reduce development cost levels and financial
exposure. As a result, producers have focused increasingly on subsea
installations and reusable FPSO systems instead of the more traditional fixed
steel and concrete platforms, which generally are not reusable.

  OUR FPSO SYSTEMS

     We provide in the following table information as of October 31, 2004 about
our four FPSO vessels. In addition to these four vessels, as of October 31, 2004
we used two FPSO shuttle tankers and one storage tanker from third-party
contractors under operating leases (some of which are in turn subleased)
expiring at various dates from 2004 through 2013. In addition, as of October 31,
2004 we owned a 40% interest in a French company that owns the FPSO Ikdam, which
is producing the Isis field located offshore Tunisia. As

                                        26
<PAGE>

of that date, production from the vessel was approximately 8,000 barrels per day
with a maximum processing capacity of 30,000 barrels per day.

<Table>
<Caption>
                                              APPROXIMATE   APPROXIMATE    PRODUCTION
                                                 TOTAL         TOTAL        CAPACITY     DISPLACEMENT     STORAGE
                                    YEAR        LENGTH         WIDTH      (BARRELS OF       (METRIC      CAPACITY
FPSO VESSEL NAME                  DELIVERED     (FEET)        (FEET)      OIL PER DAY)       TONS)       (BARRELS)
----------------                  ---------   -----------   -----------   ------------   -------------   ---------
<S>                               <C>         <C>           <C>           <C>            <C>             <C>
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
</Table>

---------------

(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/equipment under long-term charters that give us the option to
    purchase the vessel/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 19 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 in the UK sector of
the North Sea about 120 miles east of Aberdeen, Scotland. Our contract for this
work dates to 1997, and oil production from the field commenced in January 1999.
At that time, we began receiving a fixed day rate designed to cover operating
expenses and a fixed tariff per barrel of stabilized crude oil produced. Due to
the combination of a volume-dependent tariff structure, underperformance of the
reservoir and higher than expected costs of operating the field, we incurred
substantial losses on the original contract. In addition, for parts of years
2000 and 2001 we placed the vessel in the shipyard for necessary modifications
and improvements.

     In December 2003, we reached an agreement with the field operator to
substantially amend our Banff field contract. Under the amended contract,
effective January 1, 2004, we will continue to produce the Banff field with the
Ramform Banff until the end of the life of the field. The new contract contains
a two-tier production-dependent tariff that varies at different production
levels. We receive $5 per barrel of oil produced per day up to 15,400 barrels
and $3 per barrel of oil produced per day in excess of 15,400 barrels. We also
receive a fixed day rate of L40,000 per day, with a minimum total rate of
$125,000 per day. These rates are applicable for production through 2014. If
field production extends beyond 2014, we will be entitled to an increased day
rate. Under the amended contract, the field operator has the right to terminate
the contract at its sole discretion on six months' notice. Upon termination of
the contract, the field operator has the option to acquire the subsea facilities
of the Ramform Banff free of charge or cost. In the event that the field
operator does not exercise its option, we are obligated to remove the subsea
facilities at our cost and, upon completion of our obligations under the
contract, the operator will owe us five million British pounds.

     In October 2004, one well from the nearby Kyle field commenced production
through the Ramform Banff.

  PETROJARL I

     We operate the Petrojarl I under contract to Statoil to produce the Glitne
field in the Norwegian sector of the North Sea. We began production of the field
with the Petrojarl I in August 2001. Based on the most recent filed estimates by
the operator, we now expect production under the contract to continue until at
least 2007.

     The contract provides for compensation consisting of a tariff-based element
of $3.50 per barrel and a fixed day rate of $17,750, subject to a minimum of
$58,500 and a maximum of $108,500. In addition, we

                                        27
<PAGE>

are entitled to receive an additional amount of NOK 455,088 (approximately
$70,000) per day for operating expenses. Statoil may cancel the contract on six
months' notice. In addition, Statoil may terminate the contract upon specified
force majeure events; the insolvency or bankruptcy of our subsidiary K/S
Petrojarl I A/S or demonstration by that subsidiary that it is not capable of
performing the work; or our substantial breach of the contract. We may cancel
the contract on three months' notice if the minimum variable rate has been
received for 90 days in a 120 day period, subject, however, to Statoil's right
to continue the contract by increasing the tariff element.

  PETROJARL FOINAVEN

     The Petrojarl Foinaven is under contract to a consortium of field
co-operators led by Britoil PLC, a subsidiary of BP plc, for production of the
Foinaven field west of the Shetlands. The Foinaven contract is not limited as to
time. Britoil may terminate the contract with a minimum of two years' notice. We
currently expect that the vessel will remain on the field for a substantial
period. In the event of cancellation taking effect before November 2006, the
contract provides that cancellation of the contract by Britoil will trigger a
cancellation fee, payable by Britoil, of $24 million. This cancellation fee
reduces thereafter, so that no cancellation fee is payable after November 2007.
Britoil may also terminate the contract without paying a cancellation fee upon
the total loss of the vessel, a breach of the contract that is not remedied
within agreed deadlines, specified insolvency and bankruptcy related events or
specified force majeure events. In addition, we may terminate the contract with
prior notice if production-dependent tariff revenue falls below specified
levels.

     The contract provides for compensation consisting of a fixed day rate of
$70,000 and a two-tier production-dependent tariff that varies at different
production levels. We receive $3.50 per barrel of oil produced per day up to
25,000 barrels and $2.95 per barrel of oil produced per day in excess of 25,000
barrels, and we receive $0.70 per barrel of oil produced per day from East
Foinaven. The contract provides for guaranteed minimum production amounts of
51,000 barrels per day for the twelve month period that ended in November 2003,
35,500 barrels per day for the twelve month period ending November 2004 and
24,000 barrels per day for the twelve month period ending November 2005.

     We have additional obligations that may arise under the contract relating
to the Foinaven project, including obligations to:

     - compensate Britoil up to a maximum of $10 million for some breaches of
       contract; and

     - pay for pollution damage caused by diesel or lubricants.

  PETROJARL VARG

     The Petrojarl Varg operates on the Varg field on the Norwegian Continental
Shelf of the North Sea under a contract with the license owners of Production
License ("PL") 038, where production began in December 1998. Our Pertra
subsidiary has a 70% interest in PL 038, which includes the Varg field. The
remaining 30% is held by Petoro, manager of the Norwegian State's Direct
Financial Interests.

     Because of recent extensions to the life of the Varg field, we entered into
an amendment, effective from May 29, 2004, to the charter and operating
agreements with the PL 038 license owners governing production of the field.
Under the amended agreements, our compensation consists of a fixed base day rate
of $90,000 and tariff of $6.30 per barrel produced per day. Prior to May 29,
2004, our compensation consisted of a tariff of $11.12 per barrel produced per
day. The charter and operating agreements may be terminated with 90 days'
written notice, but we are not entitled to terminate the agreements as long as
the mean weekly production during normal operation on the license exceeds
approximately 15,700 barrels of oil per day.

     As a result of the reduced production from the Varg field announced on
November 8, 2004, we expect that the Petrojarl Varg will receive reduced
revenues due to the tariff-based component of the compensation arrangement
relating to the vessel. For additional information relating to the damage that
caused such reduced production, please see "-- Oil and Natural Gas Production
Segment (Pertra)" below.
                                        28
<PAGE>

  EMPLOYEE LOCKOUT AND STRIKE IN SEPTEMBER/OCTOBER 2004

     Effective September 2, 2004, the Petrojarl I was selected by the Norwegian
Shipowners Association to be included in a general employee lockout affecting
several NCS installations. Production from the Petrojarl I was shut down from
September 3 through October 27, 2004. For approximately two weeks in October
2004, production on the Petrojarl Varg was shut down as a result of a labor
conflict involving a number of service providers in the NCS. These labor
conflicts ended on October 27, 2004 after intervention by Norwegian authorities.
Because of force majeure and other payments we expect to receive for operations
during these periods, these labor matters are not expected to have a material
adverse effect on our operations.

  COMPETITION IN OUR PRODUCTION OPERATIONS

     Our production operations generally compete with other FPSO operators, with
fixed installations and tension leg platforms, with subsea production
installations tied back to existing infrastructure, with semi-submersible and
jack-up platforms and with other floating or land-based production systems.
Competition between FPSO systems and other offshore production systems is based
on a number of factors including water depth, the availability or proximity of
transportation infrastructure, the size of the producing field and time
considerations, estimated reserves, the cost and schedule for modifications, as
well as local regulatory framework. Competition tends to be limited within
segments of processing plant sophistication, operating conditions and regulatory
regimes, as FPSO systems having different specifications cannot be redeployed
easily or cost effectively between these segments. Our fleet of FPSOs is
designed specifically for harsh weather operations, limited shuttling distances
and demanding regulatory regimes, such as typically found in the North Sea and
the Atlantic Continental Shelf. The limited shuttling distances required for our
FPSOs results in relatively low need for storage capacity. In addition to the
FPSO operations and other offshore production systems of the major oil and
natural gas companies, our FPSO competitors include numerous companies that own
a small number of FPSO vessels.

     FPSOs perform similar tasks as fixed installations, with the exception of
drilling and heavy well maintenance. To combine drilling and heavy well
maintenance with production, some oil companies have opted for semi-submersible
platforms. The choice of development system between an FPSO and either a fixed
installation or another floating system is dependent on an overall technical and
financial evaluation of the individual field to be developed.

OIL AND NATURAL GAS PRODUCTION SEGMENT (PERTRA)

     In January 2002, we established a new, wholly owned subsidiary, Pertra AS
("Pertra"), to secure continued employment of the Petrojarl Varg, to pursue
small field opportunities on the NCS and to act as a facilitator for FPSO
opportunities. Pertra was formally approved in February 2002 as a license holder
and operator on the NCS of the North Sea.

     In August 2002, Pertra acquired a 70% interest in, and achieved
operatorship of, the Varg field and PL 038. Our license for PL 038 is effective
through April 1, 2011. PL 038 is located approximately 140 miles southwest of
Stavanger in the South North Sea and includes the Varg oil field and the Varg
South discovery.

     When we acquired our 70% interest in the Varg field, we also assumed 70% of
the abandonment liabilities associated with the fields on the license and any
future environmental liabilities that may be generated by production from the
fields on the license. We have no other commitments related to the license
beyond these abandonment and environmental liabilities.

     In addition to the Varg field, PL 038 comprises a number of prospects and
the Varg South field. We have acquired 3D seismic data over some areas of the
license in order to enhance our understanding of the geology and prospectivity
of these areas and are evaluating several development options. Further reservoir
studies were also performed in 2003 and 2004 to identify new drilling targets
for production wells, both in the existing boundaries of the Varg field and
additional fault blocks, including the Varg South field. In

                                        29
<PAGE>

2003 we drilled three wells, two of which were appraisal wells. In 2004, we have
drilled four wells, one of which was a water injection well. Of the wells we
drilled in 2003 and 2004, six were productive wells and one appraisal well was
unproductive. We expect to drill three to four development wells and one to two
exploration wells in 2005.

     From October 13 to October 27, 2004, production on the Varg field was shut
down as a result of a labor conflict involving a number of service providers on
the NCS. On November 8, 2004, we announced that production from the Varg field
had been reduced to approximately 15,000 barrels per day as a result of damage
to the main production riser going from the wellhead platform to Petrojarl Varg
that occurred on November 5, 2004. Production will continue at a lower rate
until the main production riser is repaired.

     In the 18th round licensing awards offshore Norway in June 2004, we were
awarded an 80% participation and operatorship in one license (PL 321) and a 30%
participation in a second license (PL 316). Our obligations under these licenses
are as described under "-- Other Factors Related to Our Business -- Capital
Expenditures" below.

     Our strategy for Pertra includes:

     - building on the success of the Varg field and the achievements in the
       18th licensing round in Norway to create a strong NCS operator on small
       fields; and

     - exploring strategic opportunities, including, among others, an evaluation
       of a potential broadening of Pertra's ownership base to facilitate and
       accelerate growth.

     We also own relatively small overriding royalty interests in oil and
natural gas production in the U.S. offshore Gulf of Mexico. We obtained these
interests at various times in return for seismic acquisition services.

     The following table presents our estimated net proved oil and natural gas
reserves as of December 31, 2003 and 2002. The December 31, 2003 reserve
estimates were prepared by company engineers and were reviewed by an independent
reservoir engineering consultant. The process of estimating natural gas and oil
reserves is complex and inherently imprecise and requires interpretations of
available technical data and many assumptions, including assumptions relating to
economic factors. Please read "Key Information -- Risk Factors -- Risk Factors
Relating Primarily to Our Oil and Natural Gas Production Activities" in Item 3
of this annual report.

<Table>
<Caption>
                                                              DECEMBER 31,
                                                              -------------
                                                              2003    2002
                                                              -----   -----
<S>                                                           <C>     <C>
PROVED CRUDE OIL RESERVES (MBBLS):
  Developed.................................................  2,114   3,272
  Undeveloped...............................................  5,704     865
                                                              -----   -----
                                                              7,818   4,137
                                                              =====   =====
</Table>

     The increase of proved undeveloped reserves from December 31, 2002 to
December 31, 2003 is primarily due to the drilling of two wells commenced in
December 2003. Production from the wells commenced in January and March 2004,
respectively.

     The table includes proved reserves for Pertra only, which was established
in January 2002. We have not included the proved reserves of our oil and natural
gas subsidiary Atlantis, which we sold in February 2003. We are treating that
subsidiary as discontinued operations for accounting purposes in this annual
report. In addition, we own small overriding royalty interests in the U.S. Gulf
of Mexico. The proved reserves associated with these overriding royalty
interests totaled 90,000 barrels of oil and 264 million cubic feet of natural
gas as of December 31, 2003.

     By October 15 of each year, we report oil and natural gas reserves
estimated as of the upcoming year end to the Norwegian government for inclusion
in the Revised National Budget. These reserves include all categories (proved,
probable and possible) and are not limited by economic cut-off. As a result,
such

                                        30
<PAGE>

reserves reported to the Norwegian government are not comparable to the proved
reserves included in this annual report.

     We had net oil production of 4,056 mbbls and 1,298 mbbls for the years
ended December 31, 2003 and 2002, respectively. Please refer to other
information regarding our oil and natural gas production in note 29 of the notes
to our consolidated financial statements included in Item 18 of this annual
report.

OTHER FACTORS RELATED TO OUR BUSINESS

  OUR RESEARCH AND PRODUCT DEVELOPMENT

     We desire to be an industry leader in those oilfield service markets in
which our advanced technologies and services may be used by customers to
discover and produce oil and natural gas in demanding environments. We are
committed to providing our customers with innovative services that help to lower
the costs of finding and producing oil and natural gas. As a result, we incur
research and development costs in an attempt to keep our key assets and services
at the forefront of engineering and technical advances. For information
regarding our research and development expenditures, please see our consolidated
statements of operations in Item 18 of this annual report.

     In 2003, we combined our research and development activities for marine
data acquisition and data processing into one technology organization. Our
research and development activities carried out in 2003 include:

     - successful development and testing of semi-solid streamers for our marine
       seismic fleet;

     - the development of new technology enabling improved seafloor seismic
       operations in deep waters;

     - testing of the first all-optical seafloor data acquisition cable offshore
       Norway;

     - development and testing of passive acoustic monitoring methods for
       monitoring whales and other aquatic mammals during seismic acquisition;
       and

     - significant improvement of our seismic processing package, the Cube
       ManagerSM.

  SEASONALITY

     We incorporate by reference in response to this item the information in
"Operating and Financial Review and Prospects -- Seasonality" in Item 5 of this
annual report.

  OPERATING CONDITIONS AND INSURANCE

     Our operations often are conducted under extreme weather and other
hazardous conditions. These operations are subject to risks of injury to
personnel and loss of equipment. We have safety compliance programs staffed by
full-time professional employees and a program for developing, implementing and
managing our responsibility for the health and safety of our employees and the
environments in which we operate. Systems for reporting and tracking the
occupational health of our employees are in place in our business units.
Company-wide initiatives focus on the further development of our environmental
management systems. We are seeking ISO environmental certification of all our
FPSO units and associated shuttle tanker fleet. We consider each employee to be
a vital contributor to health, safety and environment in our company, and we are
fully committed to our health, safety and environment program.

     In 1994, we established our own captive re-insurance company to provide
insurance for our seismic equipment, including marine acquisition vessels and
equipment, onshore equipment, data processing and information technology
hardware and software, and some of our production equipment including FPSOs and
shuttle tankers. As noted below, this insurance is subject to deductibles and
limits of coverage and is supplemented by commercial reinsurance arrangements.

     We obtain a substantial portion of our casualty insurance through this
wholly-owned captive re-insurance company. This company retains risk of $4.5
million for each accident, with a maximum annual

                                        31
<PAGE>

risk retention of $9 million per year. Our various operating companies also
retain levels of risk when obtaining this casualty insurance from the captive
company, ranging from $150,000 per accident for our seismic vessels, up to
$200,000 per accident for our streamers and $750,000 per accident for our FPSOs.

     We carry insurance for our oil and natural gas operations covering physical
loss or damage, with limits of $100 million for wellhead platforms, $5 million
for risers, $20 million for pipelines (effective from October 1, 2004) and $100
million for control of well, including redrilling, seepage and pollution. We
also carry for our oil and natural gas operations general third party liability
insurance with a limit of $100 million covering personal injury and seepage,
pollution and remediation if and when the seepage and pollution under control of
well insurance has been exhausted.

  GOVERNMENTAL REGULATION

     In various areas of the world, we are required to obtain and we have
acquired licenses to acquire multi-client seismic data. Licensing and permitting
requirements vary widely. We believe that we have complied in all material
respects with the licensing and permitting requirements relating to our
acquisition of multi-client data.

     Our operations are also affected by the exploration and production
licensing requirements of various governmental authorities. The timing and
extent of licensing of areas for exploration and production activities influence
the level of seismic activity within a particular country. Prospective licensees
often purchase multi-client seismic data prior to the award of licenses.
Following a license award, license holders will generally acquire seismic data
for the newly licensed areas if they have not previously obtained multi-client
data. In the North Sea, the governments of Norway and the United Kingdom
generally hold licensing rounds for exploration and production every two years.
In the Gulf of Mexico, licensing of blocks for exploration and production are
held twice each year, once offshore Texas and once offshore Louisiana. In other
areas, including Brazil and Brunei, the timing and extent of these licensing
rounds tend to be irregular, and the licenses awarded may be subject to
resolution of border disputes. The length of the actual license to explore for
oil and natural gas varies from region to region and is subject to governmental
regulation.

     Through our wholly owned subsidiary, Pertra AS, we hold a concession to
explore for, produce and transport petroleum under the Norwegian regulatory
framework until April 1, 2011. The Norwegian government has, and we comply with,
financial standing requirements for the grant of a production license.

     Additionally, our operations are affected by a variety of other laws 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 regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. Numerous governmental departments issue rules and
regulations to implement and enforce such laws that are often complex and costly
to comply with and that can carry substantial penalties or fines for failure to
comply. Under these laws and regulations, we may be liable for remediation or
removal costs, damages and other costs associated with releases of hazardous
materials including oil into the environment.

                                        32
<PAGE>

     We believe that we are currently in compliance in all material respects
with the requirements of environmental, export/import and occupational health
and safety laws and regulations. Please read "Key Information -- Risk
Factors -- Risk Factors Relating to Our Business Operations
Generally -- Unpredictable changes in governmental regulations could increase
our operating costs and reduce demand for our services" in Item 3 of this annual
report.

  CAPITAL EXPENDITURES

     We incorporate by reference in response to this item the information in
"Operating and Financial Review and Prospects -- Liquidity and Capital Resources
 -- Capital Requirements and Commitments" in Item 5 and note 26 of the notes to
our consolidated financial statements in Item 18 of this annual report, which,
among other things, provide information on the nature and geographic
distribution of our capital expenditures.

  GEOGRAPHIC MIX OF OPERATIONS

     We incorporate by reference in response to this item the information
regarding the geographic mix of our operations in note 26 of the notes to our
consolidated financial statements in Item 18 of this annual report.

ORGANIZATIONAL STRUCTURE

     We provide in the following table a list of our subsidiaries and affiliated
companies as of October 31, 2004.

<Table>
<Caption>
NAME                                                           JURISDICTION    OWNERSHIP
----                                                           ------------    ---------
<S>                                                           <C>              <C>
PGS Shipping AS.............................................  Norway             100%
Oslo Seismic Services Ltd. .................................  Isle of Man        100%
PGS Geophysical AS..........................................  Norway             100%
PGS Production AS...........................................  Norway             100%
PGS Reservoir AS............................................  Norway             100%
Multiklient Invest AS.......................................  Norway             100%
Pertra AS...................................................  Norway             100%
Petroleum Geo-Services, Inc. ...............................  United States      100%
Petroleum Geo-Services (UK) Ltd. ...........................  United Kingdom     100%
Seahouse Insurance Ltd. ....................................  Bermuda            100%
PGS Mexicana SA de CV.......................................  Mexico             100%
PGS Rio Bonito SA...........................................  Brazil              99%
Dalmorneftegeofizika PGS AS.................................  Norway              49%
Walther Herwig AS...........................................  Norway             100%
Geo Explorer AS.............................................  Norway              50%
Shanghai Tensor CNOOC Geophysical Ltd. .....................  United Kingdom      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%
UNACO AB....................................................  Sweden             100%
Hara Skip AS................................................  Norway             100%
</Table>

                                        33
<PAGE>

<Table>
<Caption>
NAME                                                           JURISDICTION    OWNERSHIP
----                                                           ------------    ---------
<S>                                                           <C>              <C>
PGS Exploration, SDNBHD.....................................  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 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 4 DA..............................................  Norway           99.25%
SOH, Inc. ..................................................  United States      100%
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 Investigacao Petrolifera Limitada.......................  Brazil              99%
Sea Lion Exploration Ltd. ..................................  Bahamas            100%
PGS Administracion y Servicios S.A. de C.V. ................  Mexico             100%
PGS Venezuela SA de CV......................................  Venezuela          100%
</Table>

LEASED PREMISES

     Our principal offices are at Lysaker, Norway in leased premises. We also
maintain leased premises in other cities in Norway, the United States, Angola,
Australia, Brazil, China, Egypt, England, Mexico, Nigeria, Russia, Singapore,
Scotland, the United Arab Emirates and Venezuela. We believe that all leased
properties are well maintained and are suitable and adequate for our present
activities.

                                        34
<PAGE>

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

     You should read the discussion under this caption in combination with
consolidated financial statements and the related notes in Item 18 of this
annual report and "Key Information -- Selected Financial Data" in Item 3 of this
annual report. This discussion is based upon, and the consolidated financial
statements included in Item 18 of this annual report have been prepared in
accordance with, United States generally accepted accounting principles. The
following information contains forward-looking statements. You should refer to
the section in this annual report captioned "Forward-Looking Information" for
cautionary statements relating to forward-looking statements.

OVERVIEW

     We are a technologically focused oilfield service company principally
involved in providing geophysical services worldwide and providing floating
production services in the North Sea. Globally, we provide a broad range of
geophysical and reservoir services, including seismic data acquisition,
processing and interpretation and field evaluation. In the North Sea, we own and
operate four FPSO units. We also own a small oil and natural gas company with
offshore operations on the NCS.

     In February 2003, we revised our organizational structure. Prior to
February 2003, we were organized and managed as two business segments,
geophysical and production. Due to the increased size and importance of certain
businesses within these segments and in order to improve our management
structure, we now manage our overall business in four 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;

     - Production, which owns and operates four harsh environment FPSO units in
       the North Sea; and

     - Pertra, a small oil and natural gas company that owns 70% of and is the
       operator for Production License ("PL") 038 on the NCS and also owns
       participating interests in two additional NCS licenses in areas that do
       not have current production.

     We manage our Marine Geophysical segment from Lysaker, Norway, our Onshore
segment from Houston, Texas, and our Production segment and Pertra from
Trondheim, Norway.

     We discuss our results of operations below based on these four business
segments. For a more comprehensive discussion of our history and development,
including our four business segments, key 2003 developments and our strategic
focus, please read "Information on the Company" in Item 4 of this annual report.

KEY FACTORS IMPACTING 2003 RESULTS

     You should consider the following unusual or significant items and the
following events, developments and factors in considering our results for 2003.
Each of these factors is discussed in greater detail further below in this Item
5.

     - We completed a significant financial restructuring in 2003 that included
       a voluntary Chapter 11 bankruptcy filing on July 29, 2003, emergence from
       Chapter 11 on November 5, 2003, and implementation of "fresh-start"
       accounting beginning November 1, 2003, which includes adjusting the
       recorded value of our assets and liabilities to reflect fair value as of
       that date.

     - In connection with our adoption of fresh start reporting as of November
       1, 2003, we made various changes in our accounting policies relating to,
       among other things, (a) expensing certain expenditures that previously
       were capitalized, (b) adopting the successful efforts method of
       accounting for our oil and gas operations, (c) changing our amortization
       policy for our multi-client library, and (d) changing the depreciable
       lives of our vessels.
                                        35
<PAGE>

     - The financial results for the ten month period ended October 31, 2003
       included in this annual report include significant impairment charges
       related to our long lived assets.

     - In February 2003, we sold our Atlantis oil and natural gas subsidiary for
       $48.6 million. The operating results for Atlantis for the 2003 period
       prior to sale are treated as discontinued operations in our financial
       statements.

     - We discovered material errors in previously issued financial statements.
       The consolidated financial statements included in this annual report
       reflect restated results from 2001, including restated 2001 beginning
       balances. We have not allocated these adjustments to years prior to 2001.
       Some of these restatements have carry forward effects into our results
       for 2003.

     - Our independent auditors have issued to us material weakness letters that
       identified several material weaknesses. While we believe we have made
       substantial progress in addressing these material weaknesses, they have
       not been eliminated. For additional information relating to these
       material weaknesses and the steps we have taken and are taking to remedy
       such weaknesses, please read "Controls and Procedures" in Item 15 of this
       annual report.

FINANCIAL RESTRUCTURING

     In the late 1990s, we, like other geophysical companies, invested
significantly in increased seismic acquisition capacity, in particular Marine
Geophysical capacity, to meet expected growth in oil and natural gas exploration
and production activities. During this period, we also invested heavily in our
multi-client library, in our FPSO vessel Ramform Banff and in our oil and
natural gas subsidiary Atlantis. To finance these investments, we incurred
substantial amounts of debt that required increasing amounts of our cash flow to
be devoted to debt service. The expected growth in demand for our services did
not materialize, however, and the cash flow generated by many of our investments
proved to be significantly lower than expected.

     In 2002, it became clear that a comprehensive financial restructuring was
crucial to our long-term viability and to provide a sustainable capital
structure going forward. In late 2002 we engaged financial advisors and began
discussions with representatives of our banks and bondholders with a view to
developing a comprehensive financial restructuring.

     On June 18, 2003, we announced that we had reached an agreement in
principal with a majority of our banks and bondholders, a significant holder of
our trust preferred securities, and a group of our largest shareholders to
undertake a financial restructuring of our total debt through a conversion of
our existing bank and bond debt and trust preferred securities into new debt and
a majority of our post-restructuring equity.

     On July 29, 2003, in order to implement the proposed restructuring plan, we
voluntarily filed a petition for protection under Chapter 11 of the U.S.
Bankruptcy Code with the U.S. Bankruptcy Court for the Southern District of New
York and submitted a plan of reorganization and a disclosure statement. The case
was filed only for our parent company and did not involve any of our operating
subsidiaries.

     The reorganization plan became effective and was substantially consummated
on November 5, 2003, at which time we emerged from Chapter 11 reorganization.
Pursuant to the reorganization plan, $2,140 million of our senior unsecured debt
was cancelled, and the associated creditors received the following:

     - $746 million of 10% senior unsecured notes due 2010;

     - $250 million of 8% senior unsecured notes due 2006;

     - $4.8 million of an eight-year unsecured senior term loan facility;

                                        36
<PAGE>

     - 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.

     In accordance with the reorganization plan, the existing share capital,
consisting of 103,345,987 shares, par value NOK 5 per share, 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 (one new share per 129 old shares), as well as the right to acquire 30%,
or 6,000,000, of the new ordinary shares (1,500,000 of which were committed to
shareholders underwriting the rights offering and 4,500,000 of which were
available to all pre-restructuring shareholders on a basis of one new share per
23 old shares), for $85 million ($14.17 per share) in the rights offering. In
addition, owners of $144 million of trust preferred securities received 5%, or
1,000,000, of the new ordinary shares. The principal amount of our
interest-bearing debt and capital lease obligations immediately after the
restructuring was approximately $1,210 million, a reduction of approximately
$1,283 million.

FRESH START REPORTING AND CHANGES IN ACCOUNTING POLICIES

     In connection with our emergence from Chapter 11 reorganization, we adopted
"fresh start" reporting for financial statement purposes, effective November 1,
2003, in accordance with SOP 90-7. Under SOP 90-7, we were required to adjust
the recorded value of our assets and liabilities to reflect their fair market
value as of the date we emerged from Chapter 11 reorganization, with any
shortfalls or excesses in such values, as compared to our reorganization value,
being reflected as goodwill or downward adjustments to long-lived assets,
respectively. These estimates of fair value have been reflected in our
consolidated balance sheet as of December 31, 2003.

     In connection with our adoption of fresh start accounting, we reviewed our
accounting policies with a view toward creating new policies that are less
complex, more transparent and better reflect current operations. The most
significant changes in our accounting policies are:

     - Expenditures incurred in connection with steaming and mobilization will
       be 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.

     Refer to note 2 of our consolidated financial statements included in Item
18 of this annual report for disclosure of our significant accounting policies,
including those policies that changed under fresh-start. Refer to note 3 for
disclosure of the fresh-start adjustments.

RESTATEMENT OF PREVIOUSLY ISSUED AUDITED FINANCIAL STATEMENTS

     We have restated our previously reported consolidated financial statements
for the year ended December 31, 2001. We have also restated our January 1, 2001
opening balance retained earnings for

                                        37
<PAGE>

errors that relate to prior periods. Except as otherwise specified, all
information presented in the accompanying consolidated financial statements and
the related notes include all such restatements.

     We present below the effects of the restatements on our January 1, 2001
opening retained earnings balance and our net income (loss) for the year ended
December 31, 2001.

<Table>
<Caption>
                                                              RETAINED EARNINGS   NET INCOME (LOSS)
                                                                    AS OF            YEAR ENDED
                                                               JANUARY 1, 2001    DECEMBER 31, 2001
                                                              -----------------   -----------------
                                                                    (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>                 <C>
As reported.................................................      $  94,410           $   4,453
Restatements:
  Revenue recognition.......................................        (25,297)             (2,697)
  Multi-client library (cost capitalization, impairment and
     amortization)..........................................       (100,214)            (37,649)
  FPSOs (cost capitalization, impairment and
depreciation)...............................................        (59,981)            (63,674)
  Asset retirement obligation for Banff field...............         (7,060)             (3,356)
  Contract loss accruals....................................         40,132             (31,532)
  Lease accounting..........................................         (4,980)            (23,269)
  Ceiling test for oil and natural gas assets...............             --             (20,817)
  UK leases.................................................        (41,202)              1,163
  Taxes.....................................................         53,825               3,208
  Other adjustments:
     Cost capitalization steaming, mobilization and yard
stay........................................................         (8,173)            (11,493)
     Accrued social security taxes..........................         (6,371)             (1,688)
     Errors consolidated subsidiary.........................        (11,542)              3,351
     Fair value of TES contracts............................             --               8,885
     Settlement agreement with customer.....................         (5,000)              5,000
     Various................................................        (28,410)             (2,364)
                                                                  ---------           ---------
As restated.................................................      $(109,863)          $(172,479)
                                                                  =========           =========
</Table>

     For additional information relating to the restatements, please read note 4
to the consolidated financial statements included in Item 18 of this annual
report.

     For information relating to material weaknesses in our internal controls
over financial reporting, please read "Controls and Procedures" in Item 15 of
this annual report.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     Our discussion of operating results and financial condition is based on our
consolidated financial statements, which are prepared in accordance with U.S.
GAAP. The preparation of these financial statements requires us to make
estimates and assumptions that affect the reported amount of assets and
liabilities and disclosure of contingent assets and liabilities and the amounts
of reported revenues and expenses. We evaluate our estimates and assumptions
from time to time and may employ outside experts to assist our evaluations. We
believe that our estimates and assumptions are reasonable, but we acknowledge
that actual results may vary. Our significant accounting policies are described
in note 2 to the consolidated financial statements included in Item 18 of this
annual report.

     We believe the accounting policies listed and summarized in greater detail
below are among the most critical in the preparation and evaluation of our
financial statements and involve the use of assumptions and estimates that
require a higher degree of judgment and complexity. As a result, these

                                        38
<PAGE>

policies and the related assumptions and estimates could materially affect our
reported assets, liabilities, revenues and expenses if the assumptions we make
were changed significantly, and our actual financial position, results of
operations, cash flows and future developments may differ materially from the
assumptions and estimates we have made. Our critical accounting policies and
related estimates relate to:

     - revenue recognition;

     - multi-client data library, including cost capitalization, sales and
       amortization;

     - oil and natural gas transactions, including capitalization, amortization
       and impairment;

     - long lived assets, particularly impairment and depreciation, depletion
       and amortization;

     - deferred tax assets; and

     - fresh start reporting.

  REVENUE RECOGNITION

     Our revenue recognition policy is based on the guidelines set forth in
Staff Accounting Bulletin ("SAB") Nos. 101 and 104 of the U.S. Securities and
Exchange Commission, which establishes rules for recognizing revenue for public
companies. SAB No. 101 allows revenue to be recognized only when persuasive
evidence of a sales arrangement exists, delivery has occurred or services have
been rendered, the sales price is determinable and collection is reasonably
assured.

     We recognize revenue on our contract sales of data and on our other
geophysical services as we perform the services and are able to charge these
services to the customer. The geophysical services business is of a nature where
costs from time to time are incurred and recognized prior to the time revenues
can be recognized, and as a result a non-symmetrical matching of revenues and
expenses may result in variability of results of operations between accounting
periods. We generally recognize revenue from our floating production services in
two components. First, tariff based revenues, based on barrels produced, are
recognized as production occurs. Second, day rate revenues are recognized over
the passage of time. Oil and natural gas production revenue is recognized when
the production is delivered and ownership has passed to the customer.

     Sales of data from our multi-client library generally fall into one of
three categories.

     - Late sales -- we grant a license to the customer to a specified portion
       of the library.

     - Volume sales agreements -- we grant a license or licenses to a specified
       number of blocks within the library in a defined geographical area. These
       licenses typically enable the customer to 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 late sales revenue when the customer executes a valid license
agreement and has been granted access to the library and collection is
reasonably assured. We recognize revenue 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. We recognize revenue from pre-funding arrangements as the data is
acquired, generally based on physical progress, on a proportionate performance
basis.

  MULTI-CLIENT DATA LIBRARY

     Revenue recognition relating to our multi-client library is discussed above
under "-- Revenue Recognition."

                                        39
<PAGE>

     We capitalize as an asset the costs associated with the acquisition and
processing of multi-client data. We base our amortization of the multi-client
data library on the sales forecast method. Under this method, amortization of a
survey's cost is based on the ratio between the cost of the survey and the total
forecasted sales for such survey. In applying this method following our adoption
of fresh start reporting, we categorize surveys into three amortization
categories with amortization rates of 90%, 75% or 60% of sales amounts. Each
category will include surveys where the remaining unamortized cost as a
percentage of remaining forecasted sales is less than or equal to the
amortization rate applicable to each category. We have also established maximum
book value criteria for the library projects based on a five-year life for
marine and onshore projects and a three-year life for all derivative processed
projects. The maximum book value, which we will calculate annually at year end,
is the total cost of each project less accumulated straight line minimum
amortization. We periodically evaluate the projects in the multi-client library
for impairment. Prior to our adoption of fresh start reporting, amortization was
based on the ratio of actual sales to expected sales with a minimum amortization
based on five to eight year lives.

     In determining the ordinary amortization rates applied to and fair value of
the surveys that constitute our multi-client data library, we consider expected
future multi-client sales and market developments as well as past experience.
Our sales expectations include consideration of geographic locations, prospects,
political risk, exploration license periods and general economic conditions.
These sales expectations are highly subjective, cover extended periods of time
and are dependent on a number of factors outside our control. Accordingly, these
expectations could differ significantly from year to year. Our ability to
recover costs included in the multi-client data library through sales of the
data depends upon continued demand for the data and the absence of technological
or regulatory changes or other developments that would render the data obsolete
or reduce its value.

     Over the last three years, the sales expectations for our multi-client
library have declined significantly, reflecting a weakening of the market for
multi-client data. The main effect of this decline has been an increase in
amortization rates over time and an impairment of the multi-client data library
of $90 million for the Predecessor for the ten months ended October 31, 2003,
$200.4 million for 2002 and $12.7 million for 2001.

  OIL AND NATURAL GAS ACCOUNTING

     Following our adoption of fresh-start reporting, we use the successful
efforts method of accounting for oil and natural gas properties. Under this
method, all costs of acquiring unproved oil and natural gas properties and
drilling and equipping exploration wells are capitalized pending determination
of whether the properties have proved reserves. If an exploration well is
determined to be non-productive, the drilling and equipment costs of the well
are expensed at that time. All development drilling and equipment costs are
capitalized. Capitalized costs of proved properties are amortized on a
property-by-property basis using the unit-of-production method whereby the ratio
of annual production to beginning of period proved oil and natural gas reserves
is applied to the remaining net book value of such properties. Geological and
geophysical costs are expensed as incurred.

     The estimates of proved oil and natural gas reserves as of December 31,
2003 and 2002 were prepared by our engineers in accordance with guidelines
established by the SEC and the Financial Accounting Standards Board, which
require that reserve estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations except by
contractual arrangements. Oil and natural gas reserve quantity estimates are
subject to numerous uncertainties inherent in the estimation of quantities of
proved reserves and in the projection of future rates of production and the
timing of development expenditures. The accuracy of such estimates is a function
of the quality of available data and of engineering and geological
interpretation and judgment. Results of subsequent drilling, testing and
production may cause either upward or downward revision of previous estimates.
In addition, the volumes considered to be commercially recoverable fluctuate
with changes in prices and operating costs. Reserve estimates are inherently
imprecise, and estimates of new discoveries are more imprecise than those of
currently producing oil and natural gas properties. Accordingly, we expect the
estimates relating to our reserves to change as additional information becomes
available in the future. Future changes in proved oil
                                        40
<PAGE>

and gas reserves could have a material impact on unit-of-production rates for
depreciation, depletion and amortization, as well as for impairment testing.

     Prior to our adoption of fresh start reporting, we used the full cost
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 properties are capitalized. Costs are accumulated on a country-by-
country basis. Under this method, capitalized costs were amortized using the
unit-of-production method on a country-by-country basis. Unevaluated properties
are excluded from the amortization base. Future development costs and
dismantlement and abandonment costs were included in the amortizable cost base.
In accordance with SEC guidelines, the cost bases of proved oil and natural gas
properties accounted for under the full cost method are limited, on a
country-by-country basis, to the estimated future net cash flows from proved oil
and natural gas reserves using prices and other economic conditions in effect at
the end of the reporting period, discounted at 10%, net of related taxes. If the
capitalized cost of proved oil and natural gas properties exceeds this limit,
the excess is charged to expense as additional depletion, depreciation and
amortization.

  ACCOUNTING FOR LONG LIVED ASSETS

     Effective January 1, 2002, we adopted Statement of Financial Accounting
Standards ("SFAS") No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets," which provides guidance for evaluating the recoverability of
all long-lived assets, principally property, plant and equipment and definite-
lived intangible assets, including multi-client library. SFAS No. 144 provides
similar guidance to SFAS No. 121, which was applied prior to January 1, 2002.
SFAS No. 144 requires that long-lived assets (or the group of assets, including
the asset in question, that represents the lowest level of separately
identifiable cash flows) be evaluated whenever events or changes in
circumstances indicate that the carrying amount of assets or cash generating
units may not be recoverable. We review long-lived assets or groups of assets
for impairment whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. If the total of the undiscounted future
cash flows is less than the carrying amount of the asset or group of assets, an
impairment loss is recognized for the difference between the estimated fair
value and the carrying value of the asset or group of assets. Long-lived assets
(multi-client data library, property and equipment, and proved oil and natural
gas assets accounted for under the successful efforts method) are assessed for
possible impairment upon the occurrence of a triggering event. Events that can
trigger assessments for possible impairments include, but are not limited to (a)
significant decreases in the market value of an asset, (b) significant changes
in the extent or manner of use of an asset, (c) a physical change in the asset,
(d) a reduction of proved oil and natural gas reserves based on field
performance and (e) a significant decrease in the price of oil or natural gas.
Unproved oil and gas properties are assessed for impairment in accordance with
the guidelines of SFAS No. 19. Prior to the adoption of fresh-start reporting,
oil and natural gas assets were assessed for impairment in accordance with the
full cost accounting guidelines as described under "-- Oil and Natural Gas
Accounting" above.

     Estimating undiscounted future cash flows requires us to make judgments
regarding long-term forecasts of future revenues and costs related to the assets
subject to review. These forecasts are uncertain as they require assumptions
about demand for our products and services, future market conditions and
technological developments. Significant and unanticipated changes in these
assumptions could require a provision for impairment in a future period. Given
the nature of these evaluations and their application to specific assets and
specific times, it is not possible to reasonably quantify the impact of changes
in these assumptions.

  DEFERRED TAX ASSETS

     We evaluated the need for valuation allowances for our deferred tax assets
by considering the evidence regarding the ultimate realization of those recorded
assets. We have recorded valuation allowances for 100% of net deferred tax
assets due to cumulative losses in recent years and management's expectations
about the generation of taxable income from contracts that are currently in
effect. Because of these cumulative losses and future expectations, we have
concluded that it was more likely than not that
                                        41
<PAGE>

the net deferred tax assets would not be realized and have recognized the
valuation allowances accordingly. We believe that we have valid tax planning
strategies and therefore may ultimately be successful in utilizing those net
deferred tax assets. To the extent that we continue to generate deferred tax
assets, we will continue to assess the need for valuation allowances on those
assets.

     If in the future benefits are attributed to pre-reorganization amounts, SOP
90-7 requires recognition through reduction of intangible assets until
exhausted, and thereafter as a direct addition to paid-in capital. All
significant parts of the valuation allowance of $368.5 million as of December
31, 2003 are related to pre-reorganization amounts and will only affect net
income with the reduction of amortization expense for intangible assets. If
realized benefits are attributed to post-reorganization amounts, the benefit is
recognized as a reduction of income tax expense.

  FRESH START REPORTING

     We adopted fresh start reporting upon our emergence from Chapter 11 in
accordance with SOP 90-7. Accordingly, all assets and liabilities were adjusted
to reflect their reorganization value as of November 1, 2003, which approximates
fair value at the date of reorganization. We engaged independent financial
advisors to assist in the determination of the reorganization value of the
combined entity and for most of the individual assets and liabilities. Assets
and liabilities were valued based on a combination of the cost, income and
market approach. We also considered technical, functional and economic
obsolescence. Please see "-- Fresh Start Reporting and Changes in Accounting
Policy" above.

     Similar to the estimates made for long lived assets as described above, the
estimates of fair value made for purposes of fresh start reporting required
judgments regarding long-term forecasts of future revenues and costs related to
all significant assets and liabilities. These forecasts are uncertain in that
they require assumptions about demand for our products and services, future
market conditions and technological developments. Significant and unanticipated
changes to these assumptions could require a provision for impairment in a
future period.

     In addition, with respect to our UK leases described below under
"-- Liquidity and Capital Resources -- UK Leases," we have estimated the fair
value of a specific tax exposure for contingent liabilities related to a tax
indemnity for the leases using a probability-weighted value based on a range of
possible outcomes. We have recorded a L16.7 million (approximately $28.3
million) liability as of November 1, 2003 in accordance with the requirements of
SOP 90-7. As of December 31, 2003, that liability amounted to $29.5 million. For
various reasons, including the fact that our leases differ qualitatively from
the lease structure at issue in pending legal proceedings involving third
parties, we believe it is unlikely that our leases will be successfully
challenged by the Inland Revenue. If, however, the Inland Revenue does
successfully challenge one or more of our lease arrangements, we could be liable
for substantially increased amounts under the leases. We believe that it is
likely that the final outcome of this issue will be significantly lower or
higher than the $29.5 million accrued liability as of December 31, 2003, which
could have a material effect on our results of operations, financial condition
and liquidity in future periods.

SEASONALITY

     Our Marine Geophysical segment experiences seasonality as a result of
weather-related factors. Our first and fourth quarter, in particular, are
generally negatively affected by adverse weather conditions in the North Sea,
which prevent the full operation of seismic crews and vessels. Storm seasons in
the tropics can also affect our operations when we have crews in the Gulf of
Mexico or tropical Asia. During these periods, we generally relocate our seismic
vessels to areas with more favorable weather conditions to conduct seismic
activities, or we conduct repairs and maintenance. On the other hand, our fourth
quarter revenue has historically been positively affected by end-of-year sales
of multi-client data to oil and natural gas companies. In addition, timing of
licensing activities and oil and natural gas lease sales may significantly
affect quarterly operating results.

                                        42
<PAGE>

     Our Onshore segment can also be affected by weather and seasons, depending
on where we deploy our crews at a particular time. Our Production segment and
Pertra generally do not experience material seasonal affects, other than normal
maintenance and refurbishment activities for our FPSO vessels in our Production
segment that typically take place during the summer months.

     Our results of operations fluctuate from quarter to quarter due to a number
of other factors. Our results are influenced by oil and natural gas industry
capital expenditure budgets and spending patterns. These budgets are not
necessarily spent in equal or progressive increments during the year, with
spending patterns affected by individual customer requirements and industry-wide
conditions. In addition, under our revenue recognition policy, revenue
recognition from data licensing contracts is dependent, among other things, upon
when the customer selects the data. In addition, many of our contract projects
are relatively short term. The timing of start-up and completion and crew or
vessel movement can significantly affect our results of operations from period
to period. As a result, our seismic data revenue does not necessarily flow
evenly or progressively during a year or from year to year.

RESULTS OF OPERATIONS

  OVERVIEW

     Our results of operations for the years 2003 (Successor and Predecessor),
2002 and 2001 (as restated) are presented below in an expanded format that shows
the primary components of and key drivers affecting our results of operations.
Our consolidated statements of operations show separately the ten month period
ended October 31, 2003 (Predecessor) and the two month period ended December 31,
2003 (Successor) as we emerged from Chapter 11 bankruptcy proceedings on
November 5, 2003 and adopted fresh start reporting effective as of November 1,
2003. As indicated in the discussion of our results for 2003 below, Successor
and Predecessor are in some areas combined for purposes of the discussion.
Successor financial statements are prepared on the basis of fresh start
reporting from November 1, 2003, which included changes in the carrying value of
assets and liabilities and changes to certain accounting policies.

     In addition, the results of operations presented below excludes the results
from our Production Services subsidiary (formerly Atlantic Power Group), our
Atlantis oil and natural gas subsidiary and our Tigress software subsidiary, all
of which were sold in 2002 or 2003 and are presented as discontinued operations
in our financial statements included in Item 18 of this annual report.

     We present operating results below based on our four business
segments -- Marine Geophysical, Onshore, Production and Pertra. We operate our
Marine Geophysical and Onshore businesses globally and generate revenues
primarily through contract acquisition sales and multi-client sales (pre-funding
and late sales). Our Production segment generates revenues from contract
production activities in the Norwegian and U.K. sectors of the North Sea. Pertra
generates oil production from its 70% interest in PL 038 in the Norwegian North
Sea.

                                        43
<PAGE>

  REVENUES

     The table below presents our mix of revenues for each of the three years by
business segment.

<Table>
<Caption>
                                  SUCCESSOR     PREDECESSOR
                                   COMPANY        COMPANY       COMBINED          PREDECESSOR COMPANY
                                 ------------   -----------   -------------   ---------------------------
                                  TWO MONTHS    TEN MONTHS    TWELVE MONTHS
                                    ENDED          ENDED          ENDED        YEAR ENDED     YEAR ENDED
                                 DECEMBER 31,   OCTOBER 31,   DECEMBER 31,    DECEMBER 31,   DECEMBER 31,
                                     2003          2003           2003            2002           2001
                                 ------------   -----------   -------------   ------------   ------------
                                                                                              (RESTATED)
                                                        (IN THOUSANDS OF DOLLARS)
<S>                              <C>            <C>           <C>             <C>            <C>
MARINE GEOPHYSICAL
Contract.......................    $ 48,273      $302,451      $  350,724      $  282,234      $217,271
Multi-client pre-funding.......       6,510        43,187          49,697         100,326        66,951
Multi-client late sales........      36,786       123,435         160,221         173,128       172,186
Other..........................       7,813        31,040          38,853          31,952        29,967
                                   --------      --------      ----------      ----------      --------
                                     99,382       500,113         599,495         587,640       486,375
                                   --------      --------      ----------      ----------      --------
ONSHORE
Contract.......................      18,442       106,324         124,766         102,868        84,691
Multi-client pre-funding.......       1,807        14,636          16,443          14,104         9,011
Multi-client late sales........       1,210         8,005           9,215           1,726         4,833
                                   --------      --------      ----------      ----------      --------
                                     21,459       128,965         150,424         118,698        98,535
                                   --------      --------      ----------      ----------      --------
PRODUCTION
Petrojarl1.....................      11,086        58,529          69,615          62,631        20,269
Petrojarl Foinaven.............      18,726        93,373         112,099         133,364       124,059
Ramform Banff..................       6,572        38,616          45,188          37,886        47,357
Petrojarl Varg.................       8,604        59,191          67,795          69,455        87,715
Other..........................         241           349             590           3,309        10,994
                                   --------      --------      ----------      ----------      --------
                                     45,229       250,058         295,287         306,645       290,394
OTHER/ELIMINATION..............      (3,243)      (29,369)        (32,612)         (2,449)       17,926
                                   --------      --------      ----------      ----------      --------
TOTAL REVENUES (SERVICES)......     162,827       849,767       1,012,594       1,010,534       893,230
REVENUES
  (PRODUCTS) -- PERTRA.........       9,544       112,097         121,641          32,697            --
                                   --------      --------      ----------      ----------      --------
TOTAL REVENUES.................    $172,371      $961,864      $1,134,235      $1,043,231      $893,230
                                   ========      ========      ==========      ==========      ========
</Table>

     Combined 2003 revenues for Predecessor and Successor were $91.0 million
(9%) greater than 2002 revenues, due to increased revenues in Marine
Geophysical, Onshore and Pertra, partially offset by decreased revenues in
Production. Total revenues for 2002 were $150.0 million (17%) greater than 2001
revenues, with substantial increases in each business segment in 2002 as
compared to the prior year. Pertra was not a part of our company in 2001.

     Marine Geophysical 2003 (combined) revenues increased by $11.9 million (2%)
as compared with 2002. Revenues from contract seismic acquisition increased by
$68.5 million (24%) as a result of our strategy to increase our focus on the
contract market. Revenues from multi-client pre-funding decreased $50.6 million
(50%). Our acquisition of multi-client data was reduced significantly, while the
pre-funding achieved as a percentage of cash investments in multi-client data
was 72% in 2003 (combined) compared to 76% in 2002. Multi-client late sales
decreased $12.9 million (7%) from 2002 to 2003. In 2003, we allocated a
substantially larger percentage of the active vessel time for our seismic vessel
fleet to contract acquisition rather than multi-client acquisition as compared
to 2002.

     From 2001 to 2002, we experienced substantial increases in both contract
and multi-client pre-funding sales. Total revenue increased from 2001 to 2002 by
$101.2 million (21%), one of our best year-on-year improvements, caused
primarily by higher contract revenues and higher pre-funding on our multi-client
projects.

                                        44
<PAGE>

     Onshore revenues for 2003 (combined) increased by $31.7 million (27%) as
compared with 2002. Onshore realized a significant increase both in contract and
multi-client revenues due to major new contracts in Latin America and stronger
North America multi-client late sales. From 2001 to 2002, Onshore revenues
increased by $20.2 million (20%) as our operations in Latin America began to
grow. In total, Onshore revenues increased by over $50 million from 2001 to
2003, reflecting the increased focus and growth in Latin America (particularly
Mexico) and the increased multi-client sales in the United States, partially
offset by reduced activities in Saudi Arabia.

     Production revenues decreased by $11.4 million (4%) in 2003 (combined) as
compared with 2002. This reduction was primarily attributable to a $21.3 million
decline in revenues for Petrojarl Foinaven, reflecting both a general decline in
the production level of the field and a temporary reduction in production due to
problems with one of the compressors from late June through October 2003.
Petrojarl I revenues increased in 2003 due to improvements in the production
contract for the Glitne field. Revenues from Ramform Banff increased as a result
of a temporary increase in production resulting from an additional production
well drilled early in 2003. However, production from that well subsequently
declined. Revenues from Petrojarl Varg decreased in 2003 due to a reduction in
the day rate mid 2002 and conversion from a fixed day rate to a pure production
tariff in August 2002 when we acquired 70% of PL 038, which includes the Varg
field. The Petrojarl Varg contract was further amended, effective from May 29,
2004, to change the compensation structure to a combination of a fixed day rate
and a production tariff.

     Revenues for Production in 2002 were $16.3 million (6%) higher than 2001.
The increase in 2002 was primarily attributable to increased revenues for
Petrojarl I and Petrojarl Foinaven. Revenues for Petrojarl I increased by $42.4
million (209%) from 2001 to 2002, reflecting the start up of production on the
Glitne field, which commenced in the third quarter 2001. Prior to Glitne start
up, the vessel underwent major maintenance and upgrade work at the shipyard and
was out of production for most of 2001. Revenues from Petrojarl Foinaven for
2002 were $9.3 million (8%) higher than 2001, reflecting the effects of a
production capacity upgrade, undertaken mid 2001, and an increase in production
from the field. Revenues from Ramform Banff for 2002 were $9.5 million lower
than 2001 despite the fact that the vessel was at the shipyard for an upgrade
during the first three months of 2001 and had a full year of operation in 2002.
The decline was caused by a significant reduction in production from the field.
Petrojarl Varg revenues, including the inter company revenues from Pertra,
decreased by $18.3 million (21%) in 2002 compared to 2001 primarily due to
reduced production from the Varg field.

     Since August 2002, 70% of Petrojarl Varg revenues relates to Pertra's
interest in the Varg field. These inter-segment revenues, which aggregated $45.1
million and $14.9 million in 2003 (combined) and 2002, respectively, are
eliminated in our consolidated statement of operations.

     Pertra revenues increased by $88.9 million (272%) in 2003 (combined)
compared to 2002, as Pertra became the 70% owner and operator of PL 038 in
August 2002. As a result, 2002 revenues reflect only the last five months of the
year. As indicated above, our 2001 results do not include any revenues from
Pertra. Petra's net production in 2003 (combined) was 4,056,083 barrels, with an
average realized price of $29.37 per barrel. In 2002 (which included production
from August through December), Petra's net production was 1,297,767 barrels,
with an average realized price of $27.87 per barrel.

                                        45
<PAGE>

  COST OF SALES

     The following table shows our cost of sales (products and services) by
segment as well as each segment's cost of sales as a percentage of revenues
generated by that segment:

<Table>
<Caption>
                                  SUCCESSOR     PREDECESSOR
                                   COMPANY        COMPANY       COMBINED          PREDECESSOR COMPANY
                                 ------------   -----------   -------------   ---------------------------
                                  TWO MONTHS    TEN MONTHS    TWELVE MONTHS
                                    ENDED          ENDED          ENDED        YEAR ENDED     YEAR ENDED
                                 DECEMBER 31,   OCTOBER 31,   DECEMBER 31,    DECEMBER 31,   DECEMBER 31,
                                     2003          2003           2003            2002           2001
                                 ------------   -----------   -------------   ------------   ------------
                                                                                              (RESTATED)
                                            (IN THOUSANDS OF DOLLARS, EXCEPT PERCENTAGE DATA)
<S>                              <C>            <C>           <C>             <C>            <C>
MARINE GEOPHYSICAL.............    $55,903       $248,965       $304,868        $281,324       $254,456
  % of revenue.................       56.3%          49.8%          50.9%           47.9%          52.3%
ONSHORE........................    $13,043       $ 76,634       $ 89,677        $ 98,769       $112,546
  % of revenue.................       60.8%          59.4%          59.6%           83.2%         114.2%
PRODUCTION.....................    $21,208       $133,114       $154,322        $144,261       $180,130
  % of revenue.................       46.9%          53.2%          52.3%           47.0%          62.0%
OTHER..........................    $   900       $  6,776       $  7,676        $  4,286       $  9,942
Transfer of cost(1)............       (354)       (11,093)       (11,447)          1,746             --
                                   -------       --------       --------        --------       --------
TOTAL COST OF SALES
  (SERVICES)...................    $90,700       $454,396       $545,096        $530,386       $557,074
  % of revenue.................       55.7%          53.5%          53.8%           52.5%          62.4%
                                   -------       --------       --------        --------       --------

COST OF SALES (PRODUCTS)
Pertra.........................    $11,384       $ 61,910       $ 73,294        $ 27,430       $     --
Elimination(1).................     (5,130)       (28,528)       (33,658)        (16,629)            --
                                   -------       --------       --------        --------       --------
TOTAL COST OF SALES
  (PRODUCTS)...................    $ 6,254       $ 33,382       $ 39,636        $ 10,801       $     --
  % of revenue.................       65.5%          29.8%          32.6%           33.0%            --%
                                   -------       --------       --------        --------       --------

TOTAL COST OF SALES............    $96,954       $487,778       $584,732        $541,187       $557,074
  % of revenue.................       56.2%          50.7%          51.6%           51.9%          62.4%
                                   =======       ========       ========        ========       ========
</Table>

---------------

(1) After elimination of charterhire/transfer of cost related to Petrojarl Varg.

     Cost of sales services increased $14.7 million in 2003 (combined) as
compared with 2002 primarily due to reduced multi-client activity in our Marine
Geophysical business, which had the effect of reducing the amount of costs
capitalized as multi-client investment by $63.8 million, resulting from our
increased focus during 2003 on contract marine seismic acquisition as compared
to 2002. Excluding the effect of costs capitalized as multi-client investment,
Marine Geophysical, Onshore and Production continued to show significant cost
improvements in 2003, after having reduced costs significantly in 2002. Cost of
sales services decreased $26.7 million in 2002 compared with 2001 primarily as a
result of substantial cost reductions in Onshore and Production in 2002. Most of
the cost reduction in Production related to reduced repair and maintenance
costs. We had substantial repair and maintenance costs in 2001 related to the
Ramform Banff and Petrojarl I. Both vessels were at the shipyard during the
first part of 2001.

     Cost of sales products increased $28.8 million in 2003 compared with 2002
as a result of an increase in Pertra operating costs due to a full year of
operation in 2003 compared with only five months in 2002. We had no cost of
sales products 2001 as Pertra was not part of our consolidated group in that
year.

  DEPRECIATION, DEPLETION AND AMORTIZATION

     Depreciation, depletion and amortization ("DD&A") expenses result primarily
from the allocation of capitalized costs over the estimated useful lives of our
geophysical seismic equipment (including seismic vessels), our FPSO vessels, our
seismic and operations computer equipment, leasehold improvements, buildings and
other fixtures, and depletion of our oil and gas exploration and production
assets (consisting of licenses, tangible and intangible costs of drilling wells
and production equipment) that are depleted

                                        46
<PAGE>

using a units of production method based on proved oil and gas reserves. DD&A
expenses also include the amortization of our multi-client data library ("MCDL
Amortization"), the amortization of certain intangible assets recognized upon
our adoption of fresh start reporting effective as of November 1, 2003 and
goodwill amortization for the year ended December 31, 2001.

     The following table shows our total DD&A expenses by segment. With respect
to our Marine Geophysical and Onshore segments, we have provided (1) DD&A
expenses excluding MCDL Amortization ("Adjusted DD&A") and (2) MCDL Amortization
because we believe that separately disclosing MCDL Amortization provides
investors useful information about a key component impacting the results of our
geophysical operations.

<Table>
<Caption>
                                       SUCCESSOR     PREDECESSOR
                                        COMPANY        COMPANY       COMBINED
                                      ------------   -----------   -------------       PREDECESSOR COMPANY
                                       TWO MONTHS    TEN MONTHS    TWELVE MONTHS   ---------------------------
                                         ENDED          ENDED          ENDED        YEAR ENDED     YEAR ENDED
                                      DECEMBER 31,   OCTOBER 31,   DECEMBER 31,    DECEMBER 31,   DECEMBER 31,
                                          2003          2003           2003            2002           2001
                                      ------------   -----------   -------------   ------------   ------------
                                                             (IN THOUSANDS OF DOLLARS)              RESTATED
<S>                                   <C>            <C>           <C>             <C>            <C>
MARINE GEOPHYSICAL:
  Adjusted DD&A.....................    $ 7,556       $ 59,730       $ 67,286        $ 64,616       $ 60,385
  MCDL amortization.................     29,786        131,485        161,271         183,317        173,452
                                        -------       --------       --------        --------       --------
    DD&A............................     37,342        191,215        228,557         247,933        233,837
                                        -------       --------       --------        --------       --------
ONSHORE:
  Adjusted DD&A.....................      3,251         14,292         17,543          17,077          6,340
  MCDL amortization.................      2,653         15,133         17,786          11,331          7,539
                                        -------       --------       --------        --------       --------
    DD&A............................      5,904         29,425         35,329          28,408         13,879
                                        -------       --------       --------        --------       --------
PRODUCTION:
  DD&A..............................     10,441         43,418         53,859          70,958         80,759
PERTRA:
  DD&A..............................        743         30,826         31,569          12,695
CORPORATE AND OTHER:
  Adjusted DD&A.....................        361          4,911          5,272           6,203          6,873
  MCDL amortization.................        908          1,781          2,689           1,306          1,132
                                        -------       --------       --------        --------       --------
    DD&A............................      1,269          6,692          7,961           7,509          8,005
                                        -------       --------       --------        --------       --------
TOTAL:
  Adjusted DD&A.....................     22,352        153,177        175,529         171,549        154,357
  MCDL amortization.................     33,347        148,399        181,746         195,954        182,123
                                        -------       --------       --------        --------       --------
    DD&A............................    $55,699       $301,576       $357,275        $367,503       $336,480
                                        =======       ========       ========        ========       ========
</Table>

     Adjusted DD&A for 2003 (combined) increased by $4.0 million (2%) compared
with 2002, primarily due to increased depletion of oil and gas assets in Pertra
(which was consolidated a full year in 2003 compared to five months in 2002),
partly offset by the reduced depreciation in 2003 due to the impairment of
Ramform Banff in 2002. Adjusted DD&A of the Predecessor was $153.2 million for
the first ten months of 2003. Adjusted DD&A of the Successor was $22.4 million
in the last two months of 2003 and was affected by the significant reduction in
carrying value of $455.0 million after adoption of fresh start reporting
effective as of November 1, 2003 and a reduction of estimates of useful lives
adopted for depreciation of several of the assets in our seismic and FPSO fleet.
MCDL Amortization was reduced in 2003 (combined) by $14.2 million (7%) as
compared with 2002. The reduction relates to lower pre-funding and late-sales
revenues, partially offset by a higher average amortization rate as a
consequence of reduced sales forecasts and library impairments recorded in 2002
and 2003, and adoption of fresh start reporting as of November 1, 2003. MCDL
Amortization for the ten months ended October 31, 2003 and the two months ended
December 31, 2003 were $148.4 million and $33.3 million, respectively.

     Adjusted DD&A expenses for 2002 increased by $17.2 million (11%) as
compared with 2001, primarily due to the acquisition of a 70% interest in the
Varg field (Pertra) and a significant increase in activities and equipment in
Onshore. DD&A in Production decreased by $9.8 million (12%) primarily due to the
impairment of Ramform Banff recognized in the third quarter of 2002 and reduced
goodwill

                                        47
<PAGE>

amortizations. MCDL Amortization increased $13.8 million (8%) in 2002 compared
to 2001, primarily as a result of higher multi-client pre-funding sales.

  SELLING, GENERAL AND ADMINISTRATIVE COSTS

     Selling, general and administrative costs decreased $1.7 million in 2003
(combined) as compared with 2002 and $8.6 million in 2002 as compared with 2001
primarily as a result of our cost reduction efforts in this area over the last
two fiscal years.

  IMPAIRMENTS AND OTHER OPERATING (INCOME) EXPENSE, NET

     In the first ten months (Predecessor) of 2003, we had impairments of $95.0
million, which included $90.0 million of impairment of multi-client library and
$5.0 related to other assets and equipment. In 2002 we had impairments totaling
$558.5 million, which included impairment of multi-client library of $200.4
million and impairment of seismic equipment and geophysical assets of $16.7
million. We also recorded an impairment of $332.0 million on Ramform Banff as a
result of negative development of the field and decreased prospects for
redeployment alternatives. Impairments in 2001 aggregated $12.7 million and
related primarily to the multi-client library.

     We recorded other operating (income) expense, net, of $22.4 million in 2003
(combined), primarily relating to severance payments that aggregated $19.8
million. We had other operating (income) expense, net, of $8.5 million in 2002
and $(125.6) million in 2001. The 2001 amount includes a gain of $137.0 million
from the sale of our data management business.

  INTEREST EXPENSE AND OTHER FINANCIAL ITEMS

     Interest expense for 2003 totaled $99.0 million for the first ten months
(Predecessor) and $16.9 million for the last two months (Successor), compared to
$153.3 million in 2002 and $151.6 million in 2001. Our interest expense declined
substantially in 2003 because most of our debt did not accrue interest while we
were in Chapter 11 proceedings and because of the significant reduction of our
interest bearing debt after emerging from Chapter 11 in November 2003.

     Income from equity investments totaled $1.0 million in 2003 (combined),
compared to a loss of $11.5 million in 2002 and a loss of $0.7 million in 2001.

     Other financial items for 2003 (combined) was a net expense of $5.7 million
compared to a net gain of $33.8 million in 2002. The amount for 2002 included a
gain of $45.3 million from tax equalization contracts, which were terminated in
2002.

  REORGANIZATION ITEMS

     In 2003, in connection with our completed Chapter 11 reorganization, we
recorded the following reorganization items in our consolidated statement of
operations:

     - 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 cost of
       reorganization;

     - for the first ten months (Predecessor) we recorded the net effect at
       November 1, 2003, of adopting fresh start reporting of $532.3 million.
       The amount represents the net effect of differences between the 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 "-- Financial
Restructuring" in Item 5 and in note 3 of the notes to our consolidated
financial statements included in Item 18 of this annual report. We describe our
adoption of fresh start reporting in more detail under "Fresh Start Reporting
and

                                        48
<PAGE>

Changes in Accounting Policies" in Item 5 and in note 3 of the notes to our
consolidated financial statements included in Item 18 of this annual report.

  INCOME TAX EXPENSE

     Income tax expense was $18.1 million in 2003 (combined) compared with
$185.9 million in 2002 and $28.3 million in 2001, excluding tax relating to
discontinued operations. Tax expense in 2003 included taxes payable of $24.0
million and net deferred tax benefits of $5.9 million. Taxes payable related
primarily to foreign taxes in regions where we are deemed to have a permanent
establishment and to Pertra, which is subject to petroleum taxation rules in
Norway at a nominal tax rate of 78%. Under the petroleum taxation rules, it is
not possible for Pertra to offset its income against losses from other
operations. Income tax expense in 2002 included taxes payable of $23.8 million
and net deferred taxes of $162.1 million, which reflects a substantial change in
deferred taxes in connection with exit from the shipping tax regime in Norway in
2002 and 2001 and a valuation allowance related to deferred tax asset of $61.1
million. Income tax expense in 2001 included taxes payable of $6.9 million and
net deferred taxes of $21.5 million.

  DISCONTINUED OPERATIONS

     In 2003 loss from 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). In 2002 we had $201.1 million in loss from discontinued
operations, net of tax, which included a loss related to the investment in our
Atlantis subsidiary (sale completed February 2003) of $174.5 million and a loss
of $22.6 million related to our investment in Production Services subsidiary
(sale completed December 2002).

  OPERATING PROFIT (LOSS) AND NET INCOME (LOSS)

     Operating profit for 2003 was $9.8 million for the first ten months
(Predecessor), which included impairment charges and other operating (income)
expense totaling $116.3 million, and $10.7 million for the last two months
(Successor), which included other operating (income) expense totaling $1.1
million. In 2002 we reported an operating loss of $488.6 million, after
impairment charges of $558.5 million and other operating (income) expense of
$8.5 million.

     For 2003 we reported a net income of $557.0 million for the first ten
months (Predecessor) and a net loss of $10.0 million for the last two months
(Successor). As described above, net income for the first ten months of 2003 is
significantly impacted by the effects of our financial reorganization, including
gain on debt discharge of $1,253.9 million, adoption of fresh start reporting
($532.3 million), and impairment charges ($95.0 million). Net losses for 2002
and 2001 were $1,174.7 million and $172.5 million, respectively.

OUTLOOK; FACTORS AFFECTING OUR FUTURE OPERATING RESULTS

     Our future operating results will depend on numerous factors, including
those described under "Key Information -- Risk Factors" in Item 3 of this annual
report. Factors that will impact our future operating results include the
following:

     - the development of our main market drivers, which includes prices and
       price expectations for oil and natural gas. Such prices and price
       expectations have a direct impact on the revenues of our oil and natural
       gas activities and also affect the demand for both exploration and
       production related seismic services and the economics in developing and
       producing small and medium sized oil and natural gas fields;

                                        49
<PAGE>

     - our ability to optimize performance of our FPSO vessels and profitably
       grow 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 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 HD3D 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 primary emphasis on contract work; and

      - implementation of a streamer replacement program for our seismic
        vessels;

     - the production profile of the Varg field in light of our continued
       efforts to enhance oil recovery;

     - our ability to capitalize on Pertra's position and interests on the NCS
       to gain access to exploration acreage and to discover new reserves that
       can be developed;

     - 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 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;

     - our ability to continue to develop or acquire competitive technological
       solutions for our different business units;

     - resolution of the uncertainty regarding our UK vessel leases as described
       under "Key Information -- Risk Factors -- Risk Factors Relating to Our
       Indebtedness and Other Obligations -- Potentially increased payments
       under vessel lease arrangements may adversely affect our financial
       condition, future results of operations and liquidity" in Item 3 of this
       annual report, and regarding possible tax exposure to Norwegian taxing
       authorities as discussed under "Key Information -- Risk Factors -- 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" in Item 3 of
       this annual report.

LIQUIDITY AND CAPITAL RESOURCES

  LIQUIDITY -- GENERAL

     Subject to the discussion below under "-- UK Leases," we believe that our
cash balances and our available borrowing capacity under our revolving credit
facility will be adequate to meet our working capital and liquidity needs for
the remainder of 2004 and 2005. While we believe that we have adequate sources
of funds to meet our liquidity needs for the 2004-2005 period, our ability to
meet our obligations in the longer term depends on our future performance,
which, in turn, is subject to many factors beyond our control. See "Key
Information -- Risk Factors" in Item 3 of this annual report.

                                        50
<PAGE>

  SOURCES OF LIQUIDITY -- CAPITAL RESOURCES

     Our internal sources of liquidity are cash and cash equivalents and cash
flow from operations. Cash and cash equivalents totaled $105.2 million at
December 31, 2003, an increase from $91.6 million at December 31, 2002. At
year-end 2003, we had distributed $17.9 million of the excess cash to creditors
under the terms of our plan of reorganization entered into in connection with
our financial restructuring that became effective as of November 5, 2003. We
distributed the remaining excess cash of $22.7 million in May 2004, and that
amount is included in our December 31, 2003 balance sheet in other accrued
expenses. The payment of this remaining amount was contingent on the
establishment of a $110 million two-year secured working capital facility, which
was established in March 2004 as described below.

     Net cash provided by operating activities totaled $247.0 million in 2003
(combined), representing a decrease of $46.0 million compared with 2002. Cash
flows from operating activities for 2003 were significantly impacted by the
effects of the financial restructuring that we completed during 2003. Net income
(loss) declined by $41.5 million in 2003 as compared with 2002, after reflecting
the non-cash effects of the 2003 restructuring ($1,253.9 million), changes in
impairments and fresh start adoption in 2003 compared with 2002 ($308.5 million)
and changes in deferred income taxes ($179.5 million). Operating cash flow was
negatively impacted by changes in other items aggregating $96.8 million from
2002 to 2003 (combined), offset by a positive impact caused by a reduction in
accounts receivable aggregating $64.1 million in 2003 as compared with 2002.

     Our external sources of liquidity include our secured revolving credit
facility, equipment financing and trade credit. Subject to our coming into
compliance with reporting obligations under the U.S. federal securities laws,
market conditions, availability of credit ratings and other factors, we might
also seek to raise debt or equity in the capital markets.

     In March 2004, we entered into a secured $110 million credit facility
consisting of a $70 million revolving credit facility and a $40 million letter
of credit facility. We can borrow U.S. dollars under the revolving credit
facility for working capital and general corporate purposes, and the letter of
credit facility can be utilized in multiple currencies to obtain letters of
credit to secure, among other things, performance and bid bonds required in our
ongoing business. The credit facility matures in March 2006 and is secured by
various of our assets. Borrowings under the facility bear interest at LIBOR plus
2%.

     As of December 31, 2003, interest bearing debt and capital lease
obligations were approximately $1,211 million and net interest bearing debt
(interest bearing debt and capital lease obligations less cash and cash
equivalents and restricted cash, adjusted for the final excess cash
distribution) was approximately $1,077 million.

     Certain of our loan and lease agreements and our senior note indenture
contain requirements to provide audited U.S. GAAP financial statements by June
30 of each year and to provide unaudited U.S. GAAP quarterly financial
statements within a specified period (typically 60 days) after the end of each
of the first three quarters. We have received waivers from the various lenders
allowing us to report under those agreements and the indenture under Norwegian
GAAP in lieu of U.S. GAAP until June 30, 2005.

     In addition to customary representations and warranties, certain of our
debt agreements contain covenants restricting us from incurring debt unless
specified coverage ratios are met and limiting our financial indebtedness,
excluding project debt, to $1.5 billion. These agreements also contain other
restrictions as described in note 15 to the consolidated financial statements
included in Item 18 of this annual report. See "Key Information -- Risk Factors
 -- Risk Factors Relating to Our Indebtedness and Other Obligations -- Our debt
agreements may limit our flexibility in responding to changing market conditions
or in pursuing business opportunities" in Item 3 of this annual report.

     For a description of limitations on the ability of our Norwegian
subsidiaries to pay dividends to us, please see "Financial
Information -- Dividend Restrictions" in Item 8 of this annual report. We do not
expect these limitations to affect in a material way our ability to meet our
cash obligations.

                                        51
<PAGE>

     For information relating to our outstanding indebtedness as of December 31,
2003 and the maturities of such indebtedness, please see note 15 of the notes to
our consolidated financial statements in Item 18 of this annual report.

  NET CASH USED IN INVESTING AND FINANCING ACTIVITIES

     Net cash used in investing activities totaled $94.8 million in 2003
(combined), of which $69.7 million related to the first ten months of the year
(Predecessor) and $25.1 million related to the last two months (Successor). Such
amount represents a decrease of $179.7 million compared to the total net cash
used in investing activities in 2002. We achieved this reduction in investing
activities primarily through (a) a $61.0 reduction in cash investment in
multi-client library and (b) a $75.9 million reduction in capital expenditures
effected primarily by selling our Atlantis oil and gas subsidiary and certain
other businesses.

     Net cash used in financing activities totaled $138.6 million in 2003
(combined), of which $116.6 million related to the first ten months of the year
(Predecessor) and $22.0 million related to the last two months (Successor). The
total for 2003 represents an increase of $132.6 million compared to 2002. Of
this increase, approximately $75.4 million represents an increase in net
repayment of long-term debt and principal payments under capital leases due to a
reduction in borrowings in 2003 because of our financial difficulties. An
additional $19.9 million of the increase in net cash used in financing
activities for 2003 resulted from an increase in restricted cash due primarily
to increased cash deposits used to collateralize bid bonds. In addition, in
December 2003, we made the first distribution of cash, totaling $17.9 million,
to creditors under our reorganization plan.

  CAPITAL REQUIREMENTS AND COMMITMENTS

     Our capital requirements are affected primarily by our results of
operations, capital expenditures, investments in multi-client library, debt
service requirements, lease obligations, working capital needs and outcome of
significant contingencies. The majority of our capital requirements, other than
debt service, lease obligations and contingencies, consists of:

     - capital expenditures on seismic vessels and equipment, including data
       processing equipment;

     - capital expenditures on FPSO vessels and equipment;

     - capital expenditures relating to exploration for and development of oil
       reserves in Pertra;

     - investments in our multi-client library; and

     - working capital related to growth, seasonality and specific project
       requirements.

     In prior years, our capital expenditures have related not only to normal
ongoing equipment replacement and refurbishment needs, but also to increases in
our seismic data acquisition capacity and in our FPSO operations. Such
expenditures, which can be substantial from time to time, depend to a large
extent upon the nature and extent of future commitments that are largely
discretionary. In 2003, with the exception of expenditures in Pertra to explore
and develop the Varg field, we did not make significant capital expenditures to
increase capacity.

     The following table sets forth our consolidated capital expenditures (which
does not include our investment in multi-client library) for continuing
operations in 2003 (in millions):

<Table>
<Caption>
SEGMENT                                                        AMOUNT
-------                                                        ------
<S>                                                            <C>
Marine Geophysical..........................................   $16.1
Onshore.....................................................     7.0
Production..................................................     0.5
Pertra......................................................    34.2
Other.......................................................     0.3
                                                               -----
Total.......................................................   $58.1
                                                               =====
</Table>

                                        52
<PAGE>

     For 2004, we expect:

     - to decrease our investment in multi-client library as compared to 2003 by
       continuing to focus on the contract market;

     - capital expenditures in Marine Geophysical to increase significantly to
       approximately $55-60 million as a result of increases in replacements of
       equipment for our seismic fleet, increased investment in data processing
       equipment and commencement of our streamer replacement program;

     - capital expenditures in our Onshore and Production segments to continue
       at relatively low levels because (a) we generally have a sufficient
       inventory of most equipment in our Onshore operations and (b) our FPSO
       vessels are not expected to have substantial replacement needs through
       2004; and

     - our oil and natural gas subsidiary Pertra will drill a number of
       development wells and one exploration well in PL 038 in 2004. Capital
       expenditures related to these drilling activities are expected to
       aggregate $80 million to $90 million depending on progress.

     As of October 31, 2004, we did not have any material commitments for future
capital expenditures in our Marine Geophysical, Onshore or Production segments,
except for equipment orders consistent with the descriptions above.

     In Pertra, we have the following commitments:

     - On PL 321, where Pertra is operator and holds an 80% interest, the
       license terms require us to acquire 500 square kilometers of seismic data
       by June 2010. In September 2004, Pertra, on behalf of the license owners,
       entered into a contract with our Marine Geophysical group to acquire 800
       square kilometers of seismic data at a total cost of $7.7 million for
       Pertra's share, before tax allowances. By June 2007, we are required to
       decide whether to drill one firm and one optional exploration well or
       relinquish the area.

     - On PL 316, where Pertra holds a 30% interest, the license terms require
       us to purchase an additional 800 kilometers of seismic data and drill at
       least one exploration well by June 2010. We estimate the total amount
       required to purchase the seismic data and to drill the mandatory well to
       be approximately $9 million for Pertra's share, before tax allowances.

As of October 31, 2004, our Pertra subsidiary was also in the process of
securing rig capacity for 2005 for drilling development and appraisal wells on
PL 038. We expect to commit to drilling four wells at an estimated rig cost of
$28 million for Pertra's share, before tax allowances, with the option to drill
up to three additional wells.

     In addition, we expect to spend approximately $25 million per year through
2008 to upgrade our marine seismic streamers. Since this program is
discretionary, however, we may in the future change the scope and annual capital
expenditure related to the program. We intend to make other capital expenditures
in our business segments as conditions dictate and financial resources permit.
We also intend to make maintenance and refurbishment expenditures as required so
as to maintain our fleet of marine seismic and FPSO vessels in good working
order. We also expect to continue to exploit opportunities in Pertra that could
result in significant capital outlays from time to time.

                                        53
<PAGE>

  LONG-TERM CONTRACTUAL OBLIGATIONS

     The following table presents our long-term contractual obligations and
related payments due in total and by year as of December 31, 2003:

<Table>
<Caption>
                                                      PAYMENTS DUE BY PERIOD
                                     ---------------------------------------------------------
CONTRACTUAL OBLIGATIONS               TOTAL     2004    2005 - 2006   2007 - 2008   THEREAFTER
-----------------------              --------   -----   -----------   -----------   ----------
                                                     (IN MILLIONS OF DOLLARS)
<S>                                  <C>        <C>     <C>           <C>           <C>
Long term debt obligations.........  $1,127.2   $18.5     $283.0         $27.6        $798.1
Operating lease obligations........     158.8    50.4       45.0          33.7          29.7
Capital lease obligations..........      89.3    22.7       52.6          14.0            --
                                     --------   -----     ------         -----        ------
Totals.............................  $1,375.3   $91.6     $380.6         $75.3        $827.8
                                     ========   =====     ======         =====        ======
</Table>

     For additional information about the components of our long-term debt and
lease obligations, please refer to notes 15 and 19 to the consolidated financial
statements included in Item 18 of this annual report.

     The table above does not include our accrued pension liability related to
our defined benefit pension plans, which as of December 31, 2003 totaled $45.2
million. This liability represents the aggregate shortfall of pension plan
assets compared to projected benefit obligations for our plans. This obligation
will be paid by us 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. Such requirements are
subject to change over time, but we expect these payments to be made over
several years. Please read note 21 of the notes to our consolidated financial
statements in Item 18 of this annual report for additional information relating
to our defined benefit plans.

  UK LEASES

     We have entered into vessel lease arrangements for five of our Ramform
design seismic vessels, our FPSO vessel Petrojarl Foinaven and the topsides of
our FPSO vessel Ramform Banff. In general, under the leases, UK financial
institutions acquired the assets from third parties, and we leased the assets
from the lessors under long-term charters that give us the option to purchase
the assets for a bargain purchase price amount at the end of the charter
periods. The lessors claim tax depreciation (capital allowances) on the capital
expenditures that were incurred for the acquisition of the leased assets. Under
these leases, we indemnified the lessors against specified future events that
could reduce their expected after-tax returns, including potential changes in UK
tax laws and interpretations thereof and changes in interest rates, as the
leases are based on assumed interest rates.

     The leases are legally defeased because we have made payments to
independent third-party banks in consideration for which these banks have
assumed liability to the lessors equal to basic rentals and termination sum
obligations. The defeased rental payments are based on assumed Sterling LIBOR
rates between 8% and 9%. If actual interest rates are greater than the assumed
interest rates, we receive rental rebates. If, on the other hand, actual
interest rates are less than the assumed interest rates, we are required to pay
rentals in excess of the defeased rental payments. During 2003, 2002 and 2001,
actual interest rates were below the assumed interest rates, and we made
additional required rental payments of approximately $1.5 million, $3.9 million
and $1.5 million in the ten months ended October 31, 2003 and the years ended
December 31, 2002 and 2001, respectively.

     The UK Inland Revenue ("Inland Revenue") has not signed off on the lessors'
claims to capital allowances related to our leases. We understand that the
Inland Revenue has generally deferred signing off on defeased leases (not just
ours) pending the outcome of a case that has been appealed to the House of
Lords, the highest UK court of appeal. We expect a decision from the House of
Lords in late 2004. In that case, the Inland Revenue is challenging capital
allowances associated with a defeased lease. If the House of Lords rules in
favor of the Inland Revenue's position, there is a high likelihood that the
Inland Revenue will also challenge other defeased leases.

                                        54
<PAGE>

     For various reasons, including the fact that our leases differ
qualitatively from those at issue in the pending legal proceeding described
above, we believe it is unlikely that our leases will be successfully challenged
by the Inland Revenue. In addition, we believe that any such challenge would
likely involve a lengthy process, including both trial and appellate proceedings
possibly extending over several years, to fully resolve the relevant issues. As
a result, at this point we have not considered appropriate to establish
available sources of liquidity other than our revolving credit facility to
permit us to make any necessary payments that might be required under the terms
of our leases. If we were to become liable for a substantial amount as a result
of a successful challenge to our leases by the Inland Revenue, we may not have
sources of liquidity that would permit us to pay the entire amount of such a
possible liability, which could be very large. As a result, we could be required
to seek additional sources of financing and possibly take other measures such as
reducing or delaying capital expenditures and/or selling assets. We may not be
able to take all of the actions necessary to meet these potential additional
obligations on satisfactory terms or at all. As a result, if our leases were
successfully challenged, it would likely have a material adverse affect on our
financial condition, future results of operations and liquidity.

     In addition, the Inland Revenue has raised a separate issue about the
accelerated rate at which tax depreciation is available under the UK lease
related to the Petrojarl Foinaven. If the Inland Revenue were successful in
challenging that rate, the lessor would be liable for increased taxes on
Petrojarl Foinaven in early periods (and decreased taxes in later years), and
our rentals would correspondingly increase (and then decrease).

     Please read "Key Information -- Risk Factors -- Risk Factors Relating to
Our Indebtedness and Other Obligations -- Potentially increased payments under
vessel lease arrangements may adversely affect our financial condition, future
results of operations and liquidity" in Item 3, "Financial Information -- Legal
Proceedings -- UK Legal Proceedings Involving Third Parties" in Item 8 and note
19 of the notes to our consolidated financial statements in Item 18 of this
annual report for additional information relating to these UK lease matters.

RESEARCH AND DEVELOPMENT

     We incurred research and development costs of $2.6 million, $2.8 million
and $3.8 million during the years ended December 31, 2003, 2002 and 2001,
respectively. For additional information regarding our research and development
policies and expenditures, please see "Information on the Company  -- Other
Factors Related to Our Business -- Our Research and Product Development" in Item
4 and our consolidated statements of operations in Item 18 of this annual
report.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

BOARD OF DIRECTORS

     The table below provides information about our directors as of October 31,
2004:

<Table>
<Caption>
                                                   DIRECTOR
NAME (AGE)                              POSITION    SINCE     TERM EXPIRES   SHARE OWNERSHIP
----------                              --------   --------   ------------   ---------------
<S>                                     <C>        <C>        <C>            <C>
Jens Ultveit-Moe (62).................  Chairman     2002         2005         9.6%(1)
Francis Gugen (55)....................  Director     2003         2005            *
Keith Henry (59)......................  Director     2003         2005            *
Harald Norvik (58)....................  Director     2003         2005            *
Rolf Erik Rolfsen (64)................  Director     2002         2005            *
Clare Spottiswoode (51)...............  Director     2003         2005            *
Anthony Tripodo (52)..................  Director     2003         2005            *
</Table>

---------------

(1) Controlled through Umoe Invest AS

 *  Less than 1% of our outstanding shares as of October 31, 2004.

                                        55
<PAGE>

     Mr. Ultveit-Moe has been our chairman of the board of directors since
September 2002. He is the founder and has been president and chief executive
officer of Umoe AS, a shipping and industry company, since 1984. From 2000 to
2004, he was the president of the Confederation of Norwegian Business and
Industry. From 1980 to 1984, Mr. Ultveit-Moe served as managing director of
Knutsen OAS. From 1972 to 1980, he was managing director of the tanker division
of SHV Corporation. From 1968 to 1972, Mr. Ultveit-Moe was an associate with
McKinsey & Company, Inc. in New York and London. He is chairman of the board of
directors of Unitor ASA and Kverneland ASA. Mr. Ultveit-Moe holds a master's
degree in business administration from the Norwegian School of Economics and
Business Administration and a master's degree in international affairs from the
School of International Affairs, Columbia University, New York.

     Mr. Gugen is currently active as a consultant and an investor in the energy
industry. He served with Amerada Hess Corporation for eighteen years, from 1982
to 2000, holding various positions including chief executive of Amerada Hess UK
from 1995 to 2000 and chief executive of northwestern Europe from 1998 to 2000.
Mr. Gugen acts as chairman and non-executive director for various other
companies, including CH4 Energy Limited, Island Gas Limited and The Britannia
Building Society, where he also sits on the audit committee. Mr. Gugen has
earlier worked for Arthur Andersen and has his educational background from
Nottingham University, in addition to qualifying as a UK chartered accountant.

     Mr. Henry served as group executive vice president for the Kvaerner
Engineering and Construction Group from March 2000 until June 2003. Mr. Henry
was chief executive of National Power Plc from 1995 to 1999 and was chief
executive of Brown & Root Ltd from 1990 to 1995. He acts as a non-executive
director and as an advisor to a number of energy, construction and energy
related organizations. He holds BSc and MSc degrees, and is a Fellow of the
Royal Academy of Engineering.

     Mr. Norvik is chairman and a partner of Econ Management. He served as chief
executive officer of Statoil from 1988 to 1999. He was finance director and a
member of the executive board of the Aker Group from 1981 to 1988. He served as
personal secretary to the Prime Minister of Norway and as Deputy Minister in The
Ministry of Petroleum and Energy from 1979 to 1981. Mr. Norvik has a Master of
Science Degree in Business from The Norwegian School of Economics and Business
Administration.

     Mr. Rolfsen holds several board positions. He is a member of the board of
directors of Technip S.A., Paris and Gaz de France Norge A.S. He is also
chairman of the executive council 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 Fina Exploration Norway. From
1980 to 1986, 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 senior non-executive director
at British Energy since June 2002, acts as chair of British Energy's
remuneration committee and has served as an independent director of that company
since 2001. She currently acts as non-executive chair of the boards of Busybees
and Economatters Ltd. and is a non-executive director of Advanced Technology
(UK) plc, and Tullow Oil plc. She has previously held several non-executive
director positions including Booker plc. She was director general of Ofgas, the
UK Gas Regulation Organization from 1993 to 1998. In 1993 she served as a member
of the UK Deregulation Task Force, and from 1998 to 2002 sat on the UK Public
Services Productivity Panel. Her career started as an economist with the HM
Treasury before establishing her own software company. In 1999 she was made a
Commander of the Order of the British Empire for services to industry, and holds
degrees in economics from Cambridge and Yale University.

     Mr. Tripodo has been managing director of Arch Creek Advisors LLC, an
investment banking firm, since 2003. He also serves as a non-executive director
for Cal Dive International and Vetco International Limited, both oilfield
service companies, based in Houston, Texas and London, England, respectively.
From 1997 to April 2003, Mr. Tripodo served at Veritas DGC in various
capacities, including executive vice president and chief financial officer. He
also has held various senior executive and financial roles at Baker Hughes and
PricewaterhouseCoopers. Mr. Tripodo has a B.A. degree from St. Thomas
University.

                                        56
<PAGE>

     Currently there are two alternate directors, Marianne Elisabeth Johnsen and
John Reynolds. As alternate directors they are available to fill in as needed on
a meeting to meeting basis if a regular director is unable to attend and are
also eligible to fill a vacancy on the board caused by a departure of a regular
board member.

     Ms. Johnsen is partner and founder of X-lence Group, a management
consultancy and business strategy company. Until the end of 2002 she was Vice
President Strategy and Business Development Elkem Shared Services Division at
Elkem ASA. From 1993 to 1997, she was Head of the Legal Section and
Administration Department at Ullevaal University Hospital. She has also had
positions in Norwegian Ministry of Foreign Affairs and Norwegian Ministry of
Justice. She serves on the boards of several companies: Fjord Seafood ASA,
Handicare ASA, Odin Fund Management AS and Norwegian Refugee Council. She has
previously served on boards for Ementor ASA and Aker University Hospital. She
holds a law degree from the University of Oslo and received a master's degree
with honors in business administration (MBA) from the Solvay Business School in
Brussels, Belgium.

     Mr. Reynolds is managing director of Houlihan Lokey Howard & Zukin (Europe)
Ltd., an investment bank. He has a master's in theology and religious studies
from Cambridge University, and is a fellow of the Institution of Electrical
Engineers and a fellow of the Energy Institute.

AUDIT AND REMUNERATION COMMITTEES OF THE BOARD

     Our audit committee currently consists of three members, Messrs. Gugen
(chairman), Norvik and Tripodo. Our audit committee has adopted a written
charter, a copy of which we have filed as an exhibit to this annual report.

     The audit committee acts to support the Board of Directors in the
administration and exercise of the Board's responsibility under applicable
Norwegian and other laws in connection with our financial statements and various
audit, accounting and regulatory requirements. The audit committee is
responsible for proposing to the full Board, for presentation and election at
our annual general meeting of shareholders, the independent auditors of our
company. The audit committee is also responsible for supporting the Board in the
administration and exercise of the Board's responsibility for supervisory
oversight in relation to, among other 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, 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 auditors, including the
       qualifications, performance and independence of the auditors;

     - our internal audit function; and

     - responsibilities to comply with various legal and regulatory requirements
       that could affect our financial statements.

     Our remuneration committee consists of Messrs. Henry (chairman) and
Rolfsen. The remuneration committee establishes and reviews overall policy and
structure with respect to compensation and incentive matters, including the
determination of compensation and incentive arrangements for directors,
executive officers and key employees. Our remuneration committee has adopted a
written charter, a copy of which we have filed as an exhibit to this annual
report.

                                        57
<PAGE>

SUPERMAJORITY VOTING PROVISION RELATING TO OUR BOARD

     Under our Amended Articles of Association, any change to our Board of
Directors prior to October 16, 2005 will require approval by the holders of more
than two-thirds of the votes cast as well as of the shares represented at the
shareholders meeting. In addition, as part of our 2003 restructuring, our
shareholders resolved that board decisions on certain specified major
transactions, during the same two year period, must be approved by the board
members nominated by the pre-restructuring shareholders or their successors.
These major transactions include:

     - any single sale of assets or series of sales of assets, in any calendar
       year, in excess of $100 million and not otherwise requiring approval by
       two-thirds of the shareholders in a general meeting;

     - changes to our key executive management;

     - new financings or borrowings over $25 million;

     - application of "major proceeds," which means the proceeds from the sale
       of any of our assets in excess of $100 million

     - material acquisitions, which includes any single acquisition of assets or
       series of acquisition of assets, in any calendar year, in excess of $100
       million and not otherwise requiring approval by two-thirds of the
       shareholders present and voting in a general meeting;

     - proposals to change our Articles of Association; and

     - proposals for issuance of new equity or equity-like securities.

Any changes to these instructions require approval by the holders of more than
two-thirds of the votes cast and of the shares represented at the shareholders
meeting.

EXECUTIVE OFFICERS

     The table below provides information about our executive officers as of
October 31, 2004:

<Table>
<Caption>
                                                                            EXECUTIVE
                                                                             OFFICER
NAME (AGE)                                         POSITION                   SINCE     SHARE OWNERSHIP
----------                                         --------                 ---------   ---------------
<S>                                 <C>                                     <C>         <C>
Svein Rennemo (57)................  President and Chief Executive Officer     2002         *
Gottfred Langseth (38)............  Senior Vice President and Chief           2004
                                    Financial Officer                                      *
Rune Eng (43).....................  President -- Marine Geophysical           2004         *
Eric Wersich (41).................  President -- Onshore                      2003         *
Sverre Skogen (48)................  President -- Production                   2003         *
Erik Haugane (51).................  Managing Director -- Pertra               2003         *
Anthony Ross Mackewn (57).........  Senior Vice President -- Geophysical      1999         *
Andreas J. Enger (42).............  Senior Vice President -- Group            2003
                                    Planning                                               *
</Table>

---------------

* Less than 1% of our outstanding shares as of October 31, 2004.

     Mr. Rennemo joined PGS in November 2002 as president and chief executive
officer. Prior to joining PGS, he was a partner in ECON Management. From 1997 to
March 2001, Mr. Rennemo was chief executive officer of Borealis, one of the
world's largest producers of polyolefin plastics, headquartered in Copenhagen,
Denmark, having previously served as chief financial officer and deputy chief
executive officer since 1994. From 1982 to 1994, he filled various senior
management positions within Statoil, among them group chief financial officer
and president of Statoil Petrochemicals. From 1972 to 1982, he served as a
policy analyst and advisor with the Central Bank and the Ministry of Finance in
the kingdom of Norway and the OECD Secretariat in Paris. Mr. Rennemo earned a
master's degree in economics at the University of Oslo in 1971. He is a
non-executive board member of Dynea of Finland and Nutreco of the Netherlands.

                                        58
<PAGE>

     Mr. Langseth joined PGS as senior vice president and chief financial
officer in January 2004. He was chief financial officer at Ementor ASA
(Merkantildata) from 2000 to August 2003. Mr. Langseth was senior vice president
of finance and control for Aker Maritime from 1997 to 2000. He served with
Arthur Andersen Norway from 1991 to 1997, qualifying as a Norwegian state
authorized public accountant in 1991. Mr. Langseth has a masters in business
administration from the Norwegian School of Economics and Business
Administration.

     Mr. Eng was appointed president of Marine Geophysical in August 2004. Since
joining PGS in 1997, he has held the position of area manager Scandinavia and
from 2000 has served as president for the EAME region (Europe, Africa and Middle
East). Prior to joining PGS, Mr. Eng held different positions in Fugro-Geoteam,
including a board position in Sevoteam, a Russian-Norwegian joint operating
company. Mr. Eng has a bachelor degree in applied geophysics from the University
of Oslo and a master of science degree from Chalmers University of Technology
(Sweden).

     Mr. Wersich joined Onshore in January 2000 as vice president of western
hemisphere and was appointed president of Onshore in June 2003. Mr. Wersich
worked with Western Geophysical from 1984 to 2000, employed in various
operational and management positions in North America, Latin America, Europe and
the Middle East. He is a graduate of the Colorado School of Mines, where he
earned a bachelor of engineering degree in geophysics.

     Mr. Skogen was appointed president of Production in January 2004. He
previously served as independent advisor for various projects from January 2003
to January 2004. He was president and chief executive officer of Aker Kvaerner
AS Oil & Gas from March 2002 to January 2003, president and chief executive
officer of Aker Maritime ASA from May 1997 to March 2002 and executive vice
president of Aker RGI from January 1997 to May 1997. Mr. Skogen was the founding
partner of TerraMar Prosjektledelse and helped establish TerraMar
Informasjonssystemer in 1993, which he headed until 1997. During the 1980s he
held various positions in Norwegian Petroleum Consultants, the engineering
contractor for a number of large developments on the Norwegian shelf. Mr. Skogen
has a master's of science degree in construction management, a master's degree
in business administration and a bachelor of science degree in civil engineering
from the University of Colorado.

     Mr. Haugane has been president of Pertra since its formation in January
2002. He joined PGS in 1992 as assistant manager of international development
for PGS Nopec. He acted as the Asian business development manager for PGS
Exploration from 1994 to 1996. Mr. Haugane was appointed account executive
Norway in January 1997 and senior advisor to PGS ASA in 2000. Mr. Haugane has a
master's degree in geology from the University of Tromso().

     Mr. Mackewn joined PGS as the technology director of PGS Nopec in 1993 and
transferred to PGS Exploration in 1996 as managing director of PGS Exploration
UK Ltd. He was appointed president of Exploration EAME in November 1999,
president of PGS Geophysical Services in May 2001, president of PGS Marine
Geophysical in February 2003 and group senior vice president of Geophysical in
August 2004. Prior to joining PGS, Mr. Mackewn held a number of senior positions
within the seismic services division of Schlumberger. Mr. Mackewn graduated with
an honors degree in physics from the University of Southampton in 1969.

     Mr. Enger joined PGS as vice president of group planning in January 2003.
He was previously a partner at McKinsey & Company Inc., where he led their
Middle East energy practice from 1999 to July 2002. He received a master of
science degree in engineering cybernetics from the Norwegian Institute of
Technology in 1985 and a master's degree with distinction in business
administration from INSEAD, Fontainebleau in 1988.

SHARE OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS

     As of October 31, 2004, the total number of our shares and ADSs
beneficially held by our directors (7 persons) and executive officers (8
persons) as a group was 1,915,520, representing approximately 9.6% of our
outstanding shares. Mr. Ultveit-Moe, chairman of our board of directors, is the
founder, chief

                                        59
<PAGE>

executive officer and president of Umoe Group, the parent company of Umoe Invest
AS, which as of October 31, 2004 owned 1,912,444 shares, or 9.6% of our
outstanding shares.

     On consummation of our reorganization plan, all outstanding options for
shares were cancelled without compensation to the holders, and as of October 31,
2004 we do not have board or shareholder authorization to issue shares under any
share option plan. The establishment of any management incentive plan that
includes the issuance of share options or other equity rights will require
approval of at least two-thirds of the votes cast and at least two-thirds of the
share capital represented at a shareholders' meeting, whether or not holders of
the share capital are entitled to vote.

COMPENSATION OF DIRECTORS AND EXECUTIVE OFFICERS

     For the year ended December 31, 2003, the aggregate amount we paid for
compensation to our directors and executive officers as a group for services in
all capacities during 2003 was $3.0 million. This amount includes compensation
paid to all persons who served as directors and executive officers during any
period of 2003. Mr. Rennemo, our president and chief executive officer, received
compensation for services to us during 2003 of $0.8 million. The aggregate
benefits that had accrued to our directors and executive officers as a group
(including all persons who served as such during any period of 2003) under our
various defined benefit plans for the year ended December 31, 2003 was $0.7
million (including $0.3 million in settlement of a deferred pension liability
for one of our former directors). Please read note 21 of the notes to our
consolidated financial statements in Item 18 of this annual report for
additional information relating to our defined benefit plans.

EMPLOYEES

     The following table presents information about the number of our employees
as of the end of each of the last three years:

<Table>
<Caption>
                                                                  DECEMBER 31,
                                                              ---------------------
                                                              2003    2002    2001
                                                              -----   -----   -----
<S>                                                           <C>     <C>     <C>
Marine Geophysical..........................................  1,143   1,356   1,420
Onshore.....................................................  1,479   1,828     946
Production..................................................    515     520     535
Pertra......................................................      5       6      --
Global Services/Corporate...................................    235     252     291
Discontinued Operations.....................................     --      41   1,953
                                                              -----   -----   -----
  Total.....................................................  3,377   4,003   5,145
                                                              =====   =====   =====
</Table>

     Except for the employee lockout affecting the FPSO Petrojarl I and the
strike affecting Petrojarl Varg as described in Item 4 of this annual report
under the captions "Information on the Company -- Our Production
Segment -- Employee Lockout and Strike in September/October 2004," we have not
experienced any material work stoppages related to union activities and consider
our relations with our employees to be good.

     We currently are not authorized to issue any stock options or other
stock-based awards under any stock option plan or similar plan or arrangement
for involving employees in the capital of our company. For 2004, our board of
directors has authorized a new performance bonus incentive scheme for our chief
executive officer and other executive officers. Under this scheme, the chief
executive officer is entitled to a cash bonus of up to 50% of base salary and a
share purchase bonus of up to 30% of base salary. Other executive officers are
entitled to a cash bonus of up to 40% of base salary and a share purchase bonus
of up to 20% of base salary. Within these limits, bonus will be determined on
the basis of achievement or overachievement of financial and non-financial
performance targets. Any amount received as a share purchase bonus, on a pre-tax
basis, is required to be used to buy our shares in the open market at market
price, which must be held for a minimum of three years. Implementation of the
share purchase bonus is subject to compliance with any and all applicable legal
requirements.

                                        60
<PAGE>

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

     We issued an aggregate of 20,000,000 new ordinary shares, each with a par
value of NOK 30, at consummation of our Chapter 11 reorganization in November
2003. Our share ownership following consummation of the reorganization and the
related rights offering is presented below:

<Table>
<Caption>
                                                            SHARES OF NEW PGS    PERCENT
                                                             ORDINARY SHARES    OWNERSHIP
                                                            -----------------   ---------
<S>                                                         <C>                 <C>
Former bondholders and bank debt holders..................     12,200,000          61.0%
Former trust preferred securities holders.................      1,000,000           5.0%
Pre-existing ordinary share holders.......................      6,800,000          34.0%
Total.....................................................     20,000,000         100.0%
</Table>

     Of the new ordinary shares issued, 4% were received by pre-existing
shareholders in exchange for our old shares, receiving one new share for each
approximately 129.18 pre-existing shares. The remaining 30% of our newly issued
shares held by pre-existing shareholders were purchased in a rights offering
that was underwritten by three of our major shareholders: Umoe AS ($60.0
million); Compagnie Generale de Geophysique ($22.0 million); and TS Industri
Invest AS ($3.0 million). These underwriting shareholders received the right to
acquire 1,500,000 in reserved shares as consideration for the underwriting. We
distributed the cash proceeds from the rights offering to the former bank debt
holders and bondholders who participated in the reorganization.

     Based on a Schedule 13G filed with the Securities and Exchange Commission
on January 16, 2004, Umoe Invest AS beneficially owns 1,912,444 shares, or 9.6%
of our outstanding shares. Mr. Jens Ultveit-Moe, founder, chief executive
officer and president of Umoe Group, the parent company of Umoe Invest AS,
serves as chairman of our board of directors. Please read Item 6 of this annual
report for additional information regarding Mr. Ultveit-Moe.

     Based on a Schedule 13G filed with Securities and Exchange Commission on
July 29, 2004, John A. Griffin beneficially owns 1,468,093 shares, or 7.3% of
our outstanding shares. Mr. Griffin is the Managing Member of JAG Holdings LLC
and JAG Offshore Holdings LLC, and in that capacity directs their operations.
JAG Holdings LLC is the general partner of Blue Ridge Limited Partnership, and
JAG Offshore Holdings LLC is the general partner of Blue Ridge Offshore Master
Limited Partnership. Based on the Schedule 13G, Blue Ridge Limited Partnership
and JAG Holdings LLC beneficially own 976,329 shares, or 4.9% of our outstanding
shares; and Blue Ridge Offshore Master Limited Partnership and JAG Offshore
Holdings LLC beneficially own 491,764 shares, or 2.5% of our outstanding shares.

     Our shareholders that are the beneficial owners of 5% or more of our
ordinary shares do not have different voting rights than our other shareholders.

     As of December 31, 2003, there were 24 record holders of ADSs representing
7,019,341 shares, of which 19 had registered addresses in the United States.
These 19 United States record holders held ADSs representing 7,019,341 shares,
which represented approximately 35% of the total number of our shares
outstanding as of that date.

     Based upon information available from Verdipapirsentralen, the Norwegian
centralized registry of securities, as of December 31, 2003, there were
20,000,000 ordinary shares outstanding (including shares represented by ADSs)
held by 2,992 record holders, of which 49 had registered addresses in the United
States and 2,739 had registered addresses in Norway. The United States holdings
represented 9,369,727 shares, or approximately 47% of the total number of our
shares outstanding as of that date. For this purpose, Citibank, N.A., in its
capacity as the depositary for our ADSs, represents one record holder of shares.
The above numbers may not be representative of the actual number of United
States beneficial holders or of shares beneficially held by United States
persons. The Norwegian holdings represented 2,526,321 shares, or approximately
13% of the total number of our shares outstanding as of that date.

     In the late 1990s, bank loans were extended to various of our Norwegian
employees, including some key management personnel and at least one director, in
connection with the grant of options by us during

                                        61
<PAGE>

that period. These loans were guaranteed by us, generally bore interest at 4% or
5% per annum and were intended to provide the individuals involved with funds
required to pay Norwegian taxes that were triggered by option grants. The
largest amount of outstanding loans from us to these employees during 2003
aggregated $1.7 million. Most of these loans were settled during 2003. As of
October 31, 2004, the amount of these loans outstanding aggregated $0.3 million,
with none of such outstanding loans being with any executive officers, directors
or key management personnel.

     Please read note 24 of the notes to our consolidated financial statements
included in Item 18 of this annual report for additional information regarding
our related-party transactions.

ITEM 8. FINANCIAL INFORMATION

FINANCIAL STATEMENTS

     Please read Item 18 of this annual report.

LEGAL PROCEEDINGS

  GENERAL

     From time to time, we are involved in or threatened with various legal
proceedings arising in the ordinary course of business. We do not believe that
we are engaged in, or have recently been engaged in, any additional legal or
arbitration proceedings that could have, or have had, a significant effect on
our financial position or results of operations. We are not engaged in any
material proceeding that involves any director, member of senior management or
affiliate as an adverse party to us.

  UK LEGAL PROCEEDINGS INVOLVING THIRD PARTIES

     We have entered into vessel lease arrangements for five of our Ramform
design seismic vessels, our FPSO vessel Petrojarl Foinaven and the topsides of
our FPSO vessel Ramform Banff. For a description of pending legal proceedings in
the UK involving third parties that could affect our obligations under these
lease arrangements, please read "Key Information -- Risk Factors -- Risk Factors
Relating to Our Indebtedness and Other Obligations -- Potentially increased
payments under vessel lease arrangements may adversely affect our financial
condition, future results of operations and liquidity" in Item 3 of this annual
report.

     We believe that the lease transaction and the lease structure involved in
the UK proceedings described in Item 3 of this annual report are qualitatively
different than those associated with our leases. Accordingly, even if the Inland
Revenue is successful in challenging the contested lease, that fact does not
necessarily mean that it would be successful challenging our leases. We intend
to defend vigorously any challenge of our leases by the Inland Revenue. In
addition, we believe that any such challenge would likely involve a lengthy
process, including both trial and appellate proceedings possibly extending over
several years, to fully resolve the relevant issues.

DIVIDEND RESTRICTIONS

     Our ability to meet parent company-level payment obligations depends upon
dividends, distributions, advances and other intercompany transfers from our
subsidiaries.

     Under Norwegian law, dividends in cash or in-kind as a distribution of our
profit and the profits of our Norwegian subsidiaries are only payable annually,
and any proposal by the board of directors to pay a dividend must be recommended
by the directors and approved by the shareholders at a general meeting. The
shareholders may vote to reduce, but not to increase, the dividends proposed.
Dividends in cash or in-

                                        62
<PAGE>

kind are payable only out of the following items, as computed on an
unconsolidated basis in accordance with Norwegian GAAP:

     - the annual profit according to the income statement for the last
       financial year;

     - retained profit from previous years;

     - 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 dividends if the
equity, according to our unconsolidated Norwegian GAAP balance sheet, amounts to
less than 10% of the balance sheet, or dividends in excess of an amount that is
compatible with good and careful business practice with due regard to any losses
that may have occurred after the last balance sheet date or that may be expected
to occur. We do not currently intend to declare or pay dividends. Any future
dividends will be subject to determination based upon our results of operations
and financial condition, our future business prospects, any applicable legal or
contractual restrictions, including those in our debt agreements, and other
factors that the Board of Directors considers relevant.

SIGNIFICANT CHANGES

     Except (a) as disclosed in this annual report or in our reports on Form 6-K
dated May 19 and July 29, 2004 relating to our results of operations reported
under Norwegian GAAP for the three months ended March 31 and June 30, 2004,
respectively, and (b) any adjustments required to our interim 2004 financial
statements to reflect the restatements reflected in the consolidated financial
statements and related notes included in Item 18 of this annual report, no
significant changes have occurred since the date of our 2003 annual financial
statements.

ITEM 9. THE OFFER AND LISTING

LISTING DETAILS

     Our ordinary shares are listed on the Oslo Stock Exchange and trade on that
exchange under the symbol "PGS." These shares are not listed on any other stock
exchange and are not publicly traded outside Norway.

     Each ADS represents one share. Citibank, N.A. serves as the depositary for
the ADSs. Prior to February 2003, the ADSs were traded on the New York Stock
Exchange. On February 26, 2003, the NYSE informed us that our ADSs were
suspended from the NYSE and that it would commence proceedings with the U.S.
Securities and Exchange Commission to delist the securities. Our ADSs were then
traded over-the-counter ("OTC") and were quoted on the Pink Sheets under the
ticker symbol "PGOGY."

     In November 2003, subsequent to our emergence from Chapter 11, our new
ordinary shares began trading on the Oslo Stock Exchange and our new ADSs began
trading on the OTC Pink Sheets under the symbol "PGEOY." We are using our
reasonable commercial efforts to list our ADSs on a national securities
exchange.

                                        63
<PAGE>

     You should be aware that trading in our ADSs through market makers and
quotation on the Pink Sheets may involve risk, such as trades not being executed
as quickly as when the securities were listed on the NYSE. Please read "Key
Information -- Risk Factors -- Other Risk Factors -- Because our ADSs currently
do not trade on a national exchange, you may have difficulty trading in our
ADSs" in Item 3 of this annual report.

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 New York Stock
Exchange.

<Table>
<Caption>
                                                               PRICE PER ADS
                                                              ---------------
CALENDAR PERIOD                                                HIGH     LOW
---------------                                               ------   ------
<S>                                                           <C>      <C>
1999........................................................  $24.19   $11.19
2000........................................................   19.56    10.00
2001........................................................   14.63     5.00
2002........................................................    7.89     0.35
2003 (through February 26, 2003)............................    0.48     0.31
2002
  First Quarter.............................................    7.89     4.81
  Second Quarter............................................    6.89     2.99
  Third Quarter.............................................    3.52     0.39
  Fourth Quarter............................................    0.69     0.35
</Table>

     We have presented in the table below, for the periods indicated, the
reported high and low closing prices for our ADSs on the Pink Sheets. Upon
emergence from Chapter 11 proceedings and consummation of our financial
restructuring, the pre-restructuring shareholders received one post-
restructuring share per 129 old shares held in addition to the right to
subscribe for new shares in a rights offering.

<Table>
<Caption>
                                                               PRICE PER ADS
                                                              ---------------
CALENDAR PERIOD                                                HIGH     LOW
---------------                                               ------   ------
<S>                                                           <C>      <C>
2003 (February 26, 2003 - November 5, 2003).................  $ 1.49   $ 0.10
2003 (from November 6, 2003)................................   43.00    32.80
2003 (from February 26, 2003)...............................   43.00     0.10
  First Quarter.............................................    0.20     0.10
  Second Quarter............................................    0.66     0.15
  Third Quarter.............................................    1.03     0.58
  Fourth Quarter (through November 5, 2003).................    1.49     0.34
  Fourth Quarter (from November 6, 2003)....................   43.00    32.80
2004
  First Quarter.............................................   51.20    38.05
  Second Quarter............................................   48.00    33.50
  Last Six Months
     October................................................   48.85    37.50
     September..............................................   48.50    41.35
     August.................................................   38.50    36.25
     July...................................................   41.00    37.00
     June...................................................   41.60    35.50
     May....................................................   44.60    34.50
</Table>

SHARES

     We have presented in the table below, for the periods indicated, the
reported high and low closing prices for our shares on the Oslo Stock Exchange.
Upon emergence from Chapter 11 proceedings and

                                        64
<PAGE>

consummation of our financial restructuring, the pre-restructuring shareholders
received one post-restructuring share per 129 old shares held in addition to the
right to subscribe for new shares in a rights offering.

<Table>
<Caption>
                                                                PRICE PER SHARE
                                                              -------------------
CALENDAR PERIOD                                                 HIGH       LOW
---------------                                               --------   --------
<S>                                                           <C>        <C>
1999........................................................  NOK185.5    NOK84.0
2000........................................................     174.0       91.5
2001........................................................     124.5       44.0
2002........................................................      70.0        2.6
2003 (through November 5, 2003).............................      10.9        1.1
2003 (from November 6, 2003)................................     315.0      213.0
2002
  First Quarter.............................................      70.0       41.0
  Second Quarter............................................      59.0       23.0
  Third Quarter.............................................      27.5        2.6
  Fourth Quarter............................................       5.3        2.6
2003
  First Quarter.............................................       3.1        1.1
  Second Quarter............................................       5.1        1.1
  Third Quarter.............................................       7.0        4.4
  Fourth Quarter (through November 5, 2003).................      10.9        6.9
  Fourth Quarter (from November 6, 2003)....................     315.0      213.0
2004
  First Quarter.............................................     365.0      262.0
  Second Quarter............................................     337.0      245.0
  Last Six Months
     October................................................     330.0      293.5
     September..............................................     330.0      278.0
     August.................................................     277.5      248.5
     July...................................................     289.0      265.0
     June...................................................     292.5      254.0
     May....................................................     310.0      245.0
</Table>

ITEM 10. ADDITIONAL INFORMATION

DESCRIPTION OF SHARE CAPITAL

     We have summarized below material information about our share capital, our
articles of association and provisions of Norwegian law that apply to our share
capital. This summary is not complete. For more information about our share
capital, we encourage you to read our articles of association, which we have
filed as an exhibit to this annual report.

ORGANIZATION, REGISTER AND PURPOSE

     We are a public limited liability company organized under the laws of the
Kingdom of Norway. Our registration number with the Norwegian Company Registry
is 916235291. As set forth in Section 2 of our articles of association, our
business is to provide services to and participate and invest in energy related
businesses.

VOTING RIGHTS

     As a general rule, our shareholders can take action under Norwegian law or
our articles of association by a simple majority of votes cast at a general
meeting of shareholders. Each ordinary share carries one vote. Amendments to our
articles of association, however, including any amendment increasing our share

                                        65
<PAGE>

capital or altering the rights and preferences of any share or class of shares,
require the approval of at least two-thirds of the votes cast and at least
two-thirds of the share capital represented at a shareholders' meeting, whether
or not holders of the share capital are entitled to vote. In some cases, a
stricter voting requirement may apply.

     Before October 16, 2005, the election of a new director as a replacement
for an incumbent director prior to the expiration of the term of the incumbent
director must be approved at a shareholders' meeting by more than two-thirds of
the votes cast and more than two-thirds of the share capital represented at the
meeting. After October 16, 2005, a simple majority will be sufficient to elect a
new director, both before and after the expiration of an incumbent's term of
office.

     To vote at an annual or extraordinary general meeting, a shareholder must
be registered as a holder of title to the shares to be voted in our share
register maintained at Verdipapirsentralen ("VPS"), the Norwegian centralized
registry of securities, not later than at the date of the general meeting.
Shareholders who intend to participate in a general meeting in person or by
proxy must notify us by the date stated in the notice convening the meeting.
This date may not be more than two business days before the date of the meeting.

     Under our articles of association, the beneficial owner of shares
registered in VPS through a custodian approved by the Norwegian authorities may
vote the shares covered by the custodial 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 owners described
above, under Norwegian law, owners of ADSs representing shares can vote by
surrendering their American Depositary Receipts, or ADRs, evidencing ADSs to the
custodian and having title to the related shares registered in our share
register maintained at the VPS prior to the meeting.

     Our annual general meeting of shareholders is held each year before the end
of June. Norwegian law requires that written notice of general meetings be sent
to shareholders whose addresses are known at least two weeks prior to the date
of the meeting. Under our articles of association, we may call ordinary general
meetings on four weeks' written notice and extraordinary general meetings on two
weeks' written notice. A shareholder may vote by proxy. Although Norwegian law
does not require us to send proxy forms to our shareholders for general
meetings, we normally include a proxy form with the notice of meetings. Any
shareholder may demand that a specific issue be placed as an item on the agenda
for any general meeting provided that we are notified in time for such item to
be included in the meeting notice.

     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.

     The request must name the matters to be considered. The extraordinary
general meeting must be convened within one month of the date of the request.
Other than approval of the annual accounts any matter that may be raised at an
annual general meeting may also be raised at an extraordinary general meeting.

     Norwegian law prohibits the general meeting or the board of directors of
any other person representing us from taking any action that may give a
shareholder an unreasonable benefit at the expense of other shareholders or us.

                                        66
<PAGE>

RESTRICTIONS ON OWNERSHIP OF SHARES

     At present, there is no limitation on ownership of shares by persons who
are not Norwegian. The board of directors, as required by the articles of
association, will refuse to approve any transfer of our shares insofar as such
share acquisition may impair any license to acquire real property or other
rights held by us or any of our subsidiaries, or our chances of later acquiring
such license. We do not presently hold any license or concession which could be
impaired by such an acquisition of our shares.

SHARE REGISTER

     Under Norwegian law, shares are registered in the name of the owner of the
shares. As a general rule, there are no arrangements for nominee registration.
However, shares may be registered in the VPS, described further below, by a fund
manager (bank or other nominee) approved by the Norwegian Ministry of Finance,
as the nominee of foreign shareholders. An approved and registered nominee has a
duty to provide information on demand about beneficial shareholders to the
company and to the Norwegian authorities. In the case of registration by
nominees, registration with the VPS must show that the registered owner is a
nominee. Registration must include the nominee's name, address and number of
shares, which are the subject of the nomination agreement. A registered nominee
has the right to receive dividends and other distributions but cannot vote at
general meetings on behalf of the beneficial owners. Beneficial owners must
register with the VPS or provide other proof of their acquisition of the shares
in order to vote at general meetings.

VPS AND TRANSFER OF SHARES

     Norway has a paperless, centralized registry of shares and other
securities, VPS. We and all other Norwegian public companies are obligated to
register our shares in VPS. Share certificates are not used. VPS is a
computerized bookkeeping system operated by an independent body in which the
ownership of and all transactions relating to Norwegian listed shares must be
recorded. Our share register is operated through VPS under VPS number
000-4225004.

     All transactions relating to securities registered with VPS are made
through computerized book entries. VPS confirms each entry by sending a
transcript to the registered shareholder irrespective of any beneficial
ownership. To effect an entry, the individual shareholder must establish a share
account with a Norwegian account agent. Norwegian banks, the Bank of Norway,
authorized securities brokers in Norway and Norwegian branches of credit
institutions established within the European Economic Area are allowed to act as
agents. If the shareholder does not establish an account, the issuing company
will appoint an agent on the shareholder's behalf.

     A VPS entry represents prima facie evidence in determining the legal rights
of a registered holder of a security against the issuing company or a third
party claiming an interest in the security.

     VPS is strictly liable for any loss resulting from an error in connection
with registering, altering or canceling a right, except in the event of
contributory negligence, in which event compensation owed by the VPS may be
reduced or withdrawn.

     Under Norwegian law, a transferor must register immediately with VPS any
acquisition or other transfer of shares. A person to whom shares have been
transferred or assigned may exercise the rights 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 a transfer of shares is subject to
approval by our board of directors. The approval cannot be withheld without
reasonable grounds. This provision could operate to prevent or impede a change
in control of PGS.

                                        67
<PAGE>

ADSS AND TRANSFER AND VOTING

     Our shareholders may choose to hold our shares as ADSs, in which case the
shares are represented by ADRs. ADSs may be transferred, at the option of the
holder, by transferring the related ADRs, or by requesting the underlying shares
to be issued to the holder, who transfers them to the transferee. A holder of
ADSs may vote their shares by either:

     - requesting to be certificated by having the underlying shares transferred
       to a VPS account in the name of the holder; or

     - presenting themselves as a shareholder, providing name and address, and a
       confirmation from Citibank N.A. as depositary for the ADSs to the effect
       that they are the beneficial owner of the underlying shares; or

     - authorizing Citibank N.A. to vote the ADSs on their behalf.

DISCLOSURE OBLIGATIONS

     Under Norwegian law, a person, entity or group acting in concert must
notify the Oslo Stock Exchange immediately of an acquisition or disposition of
shares and/or rights to shares and of its aggregate holdings of shares and/or
rights to shares following the acquisition or disposition if the acquisition or
disposition results in its aggregate beneficial ownership of shares and/or
rights to shares reaching, exceeding or falling below thresholds of 1/20, 1/10,
1/5, 1/3, 1/2, 2/3 or 9/10 of the total number of shares outstanding or of the
outstanding voting rights. A corresponding disclosure obligation applies to any
holder of ADRs.

ADDITIONAL ISSUANCES AND PREEMPTIVE RIGHTS

     To issue additional shares, including bonus issues (share dividends), we
must amend our articles of association. This amendment requires the same
shareholder vote as other amendments to our articles of association, which is
more than two-thirds of the votes cast and more than two-thirds of the share
capital represented at the meeting. Our shareholders also must approve by the
same vote the issuance of loans convertible into shares or warrants to purchase
shares. At a general meeting, the shareholders may by the same majority
authorize our board of directors 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 a preemptive right to subscribe for
and be allotted new shares that we issue. Shareholders may waive those
preemptive rights in a general meeting by the same vote required to approve
amendments to our articles of association. A waiver of the shareholders'
preemptive rights for bonus issues (share dividends) must be approved by the
holders of all shares outstanding.

     If we issue shares upon the exercise of preemptive rights to holders who
are citizens or residents of the United States, we may be required to file a
registration statement in the United States under United States securities laws.
If we decide not to file a registration statement, those U.S. holders will not
be able to exercise their preemptive rights and would be required to sell them
to Norwegian persons or other non-U.S. holders to realize the value of the
rights.

                                        68
<PAGE>

     Under Norwegian law and with shareholder approval, we may distribute bonus
issues (share dividends) of our shares from amounts:

     - that we could otherwise distribute as dividends; and

     - 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 by issuing shares or
by increasing the par value of the shares outstanding.

DIVIDENDS AND LEGAL RESERVES

     Please read "Financial Information -- Dividend Restrictions" in Item 8 of
this annual report for information regarding our ability to pay dividends and
whether we intend to pay dividends. We hereby incorporate information called for
by this Item 10 by reference to the information under that caption.

     Under Norwegian law, we are required to maintain reserves that are adequate
in light of our activities and related risks. We must allocate to the share
premium (restricted) reserve any premium paid to us for the subscription of new
shares.

EXAMINATION OF PGS AND ITS ACCOUNTS

     Under Norwegian law, any shareholder may request the Norwegian courts to
order an examination of our company and accounts if such request is approved by
10% or more of the aggregate share capital represented at any general meeting.

RIGHTS UPON WINDING-UP

     A Norwegian company may be wound up by a resolution of the company in a
general meeting passed by a two-thirds majority of the aggregate votes cast by
its voting shares and by two-thirds of the aggregate share capital represented
at the meeting irrespective of class. The shares rank pari passu in the event of
a return of capital by the company on a winding-up or otherwise.

INTERESTED DIRECTOR TRANSACTIONS

     Under Norwegian law, a director may not participate in the discussion or
decision of any matter in which the director or any related person of the
director has a significant personal or financial special interest. In addition,
under Norwegian law, a director may not participate in a matter concerning a
loan or other credit to the director or the pledging of security for the
director's debt.

OTHER PROVISIONS RELATING TO DIRECTORS

     Under Norwegian law, any compensation payable to a director must be
determined by the shareholders in a general meeting. There is no mandatory
retirement provision under Norwegian law or our articles of association, nor is
there a requirement that our directors own our shares or ADSs.

MANDATORY BID REQUIREMENT

     Norwegian statutory law requires any person, entity, family group or other
group acting in concert that acquires shares (including ADSs) representing more
than 40% of the voting rights of a Norwegian company listed on the Oslo Stock
Exchange to notify the Oslo Stock Exchange immediately and to make a general
offer to acquire all the outstanding share capital of that company. Such offer
must be made no later than four weeks after the obligation is triggered and in
the form of an offer document to all shareholders. The offer may not be
conditional and is subject to approval by the Oslo Stock Exchange

                                        69
<PAGE>

before submission to the shareholders. The offer must be in cash or contain a
cash alternative at least equivalent to any other consideration offered. 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 acquiror acquires, or agrees to acquire, additional shares at a
higher price after exceeding the 40% threshold but prior to the expiration of
the four-week bid period, the acquiror must restate its bid at that higher
price. If a shareholder who is required to make a mandatory bid fails to do so,
the shareholder must within four weeks dispose of sufficient shares so that the
obligation ceases to apply. Otherwise, the Oslo Stock Exchange may cause the
shares exceeding the 40% limit to be sold by public auction.

     During the time the mandatory bid requirement is in force, a shareholder
failing to make the required offer may not vote or exercise any rights of share
ownership other than the right to receive dividends and preferential rights
relating to a share capital increase, unless a majority of the remaining
shareholders approve. In addition, the Oslo Stock Exchange may impose a daily
fine upon a shareholder who fails to make the required offer.

     Citibank, N.A., the depositary, has qualified and been recognized as a
custodian of the shares in Norway. As a result, 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 the sale, lease or
exchange of all or substantially all of the property or assets of a Norwegian
company requires shareholders approval in addition to the approval of the board
of directors, unless such a transaction would imply that the business and
purpose of the company as described in its articles of association would be
amended, in which event the approval of more than two-thirds of the votes cast
and more than two-thirds of the share capital represented 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 than 90% of the total number of
shares outstanding or of the outstanding voting rights, then such majority
shareholder has the right (and each remaining minority shareholder of the
company has the right to require such majority shareholder) to effect a
compulsory acquisition for cash of any shares not already owned by such majority
shareholder. Such compulsory acquisition would imply that the majority
shareholder has become the owner of the acquired shares with immediate effect.
On effecting the compulsory acquisition, the majority shareholder would have to
offer the minority shareholders a specific price per share, the determination of
which price would be at the discretion of the majority shareholder. If any
minority shareholder does not accept the offered price, such minority
shareholder may, within a specified deadline not less than two months, request
that the price be set by the Norwegian courts. Generally, the cost of any such
court procedure would be borne by the majority shareholder, and the courts would
have full discretion in respect of the valuation of the shares for the
compulsory acquisition. In the absence of such a request or other objection to
the price being offered by the majority shareholder, the minority shareholders
would be deemed to have accepted the offered price after the expiration of a
two-month period.

EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS

     Under Norwegian foreign currency exchange controls currently in effect,
transfers of capital to and from Norway are not subject to prior governmental
approval except for the physical transfer of 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 a Norwegian
exchange control consent, but the payments must be made through a licensed bank.
                                        70
<PAGE>

     There are no limitations imposed by Norwegian law or our articles of
association on the right to hold or vote shares that apply differently to
non-Norwegian owners than to Norwegian owners.

TAXATION

  GENERAL

     The following discussion generally summarizes the principal Norwegian and
U.S. federal income tax consequences of the ownership and disposition of our
ADRs, which evidence our ADSs, and our shares to holders of ADRs and shares who
are residents of the United States or otherwise subject to U.S. federal income
taxation on a net income basis for ADRs and shares and who are not residents of
Norway ("U.S. Holders"). The summary applies only to holders who will hold ADRs
or shares as capital assets and does not address certain classes of holders,
such as holders who own, directly or indirectly, at least 10% of our outstanding
shares, that may be subject to special rules. Because it is a general summary,
prospective purchasers of ADRs or shares who would be U.S. Holders are advised
to consult their own tax advisors about the U.S. federal, state and local tax
consequences and the Norwegian tax consequences of the ownership and disposition
of ADRs and shares that are applicable in their particular tax situations,
including the effects of recent and possible future changes in the applicable
tax laws.

     The summaries of U.S. and Norwegian tax laws provided below are based on
the tax laws of the United States and Norway, the income tax convention between
the United States and Norway (the "Convention") and interpretations by the
relevant tax authorities that are in effect as of the date of this annual report
and are subject to any changes that may occur after that date (possibly with
retroactive effect). Several amendments to Norwegian tax law have been proposed
in the national budget in Norway for 2005. The proposals include, among others,
an exemption from taxation for dividends and gains from disposal of shares for
corporate shareholders, although individual shareholders would continue to be
subject to taxation of such dividends and gains. The amendments are expected to
be enacted during 2004, with some retroactive effect.

     For U.S. and Norwegian tax purposes, U.S. Holders of ADRs will be treated
as the owners of the shares represented by the ADRs. Unless we have otherwise
stated below, the Norwegian tax consequences and the U.S. federal income tax
consequences discussed below apply equally to U.S. Holders of ADRs and U.S.
Holders of shares.

     We believe, and this discussion assumes, that we are not and have never
been a foreign personal holding company, a foreign investment company, or a
passive foreign investment company as those terms are defined in the U.S.
Internal Revenue Code of 1986, as amended (the "Code").

  TAXATION OF DIVIDENDS

     Under Norwegian tax law, dividends paid to foreign shareholders of
Norwegian corporations are, unless otherwise provided for in an applicable tax
treaty, subject to a withholding tax in Norway of 25%. Under the Convention, the
maximum rate of withholding tax on dividends paid by a Norwegian corporation to
a "resident of the United States," as defined in the Convention, is 15%. The 15%
withholding rate will apply to any dividends paid on our shares held directly by
U.S. Holders who properly demonstrate to us and to the Norwegian tax authorities
that they are entitled to the benefits of the Convention. Dividends paid to
Citibank, as depositary, will be subject to withholding at the 25% rate. U.S.
Holders of ADRs who believe they are entitled to the benefits of the Convention
may apply to the Norwegian tax authorities for a refund of amounts withheld in
excess of 15%. The application is to be filed with the Norwegian Tax
Directorate. There is some uncertainty, however, as to whether and when such a
refund may be obtained. The proposed amendments to the Norwegian tax law would
not affect the withholding tax on dividends distributed to residents of the
United States.

     We intend to file any reports with the Norwegian authorities or agencies
necessary to obtain the benefits of the Convention for those entitled to them.
We will exercise our right under the deposit

                                        71
<PAGE>

agreement to reasonably request from Citibank such information from its records
that will enable us to file the reports.

     If, however, the recipient of a dividend is determined to be engaged in a
business activity taxable in Norway and our shares or ADSs with respect to which
the dividend is paid are effectively connected with that activity, then the
amount distributed to the U.S. Holder will be treated as taxable domestic
dividend income in Norway, subject to the provisions of the Convention, where
applicable. Under the proposed amendments to the Norwegian tax law, the dividend
would be exempted from taxation in Norway if the business activity in Norway is
owned by a corporate entity in the United States.

     To the extent paid out of our current or accumulated earnings and profits,
distributions made on our shares or ADSs, other than certain distributions of
our capital stock or rights to subscribe for shares of our capital stock, will
be includible in the income of a U.S. Holder for U.S. federal income tax
purposes as ordinary dividend income. In the case of a U.S. Holder of an ADR,
such dividend income will be recognized on the date Citibank receives the
distribution. Dividends we pay will not be eligible for the dividends-received
deduction generally allowed to corporations under the Code. The amount of a
dividend distribution for tax purposes will equal the U.S. dollar value of the
amount of the distribution in Norwegian kroner (including the amount of
Norwegian taxes withheld from the distribution), calculated by reference to the
exchange rate in effect on the date of the distribution. Upon the ultimate
conversion by Citibank into U.S. dollars of the Norwegian kroner received in a
distribution, U.S. Holders of ADRs generally will recognize gain or loss for
U.S. federal income tax purposes equal to the difference, if any, between such
U.S. dollars and the U.S. dollar value of such Norwegian kroner on the date of
the distribution. Such gain or loss will be treated as ordinary income or loss.

     For tax years beginning after December 31, 2002 through tax years beginning
on or before December 31, 2008, dividend income received by an individual,
estate, or trust from a corporation organized in the U.S. or from a "qualified
foreign corporation" generally is taxed at the lower rates imposed on long-term
capital gains recognized by individuals. The maximum rate of tax for such
dividends is 15%.

     A non-U.S. corporation is a "qualified foreign corporation" if either (i)
its stock with respect to which the dividend is paid is readily tradable on a
qualifying U.S. stock exchange or (ii) the corporation is eligible for the
benefits of a comprehensive tax treaty with the U.S. that the Internal Revenue
Service ("IRS") determines is satisfactory for purposes of the provision
reducing the rate of tax on dividends, and that includes an exchange of
information program. It is undetermined whether our shares or ADRs will be
traded on a qualifying U.S. stock exchange. However, we are eligible for
benefits under the Convention, and the IRS has identified the Convention as
satisfactory for purposes of the provision reducing the rate of tax on dividends
and as including an exchange of information program. Accordingly, U.S. Holders
that are individuals, estates, or trusts generally will be eligible for the
lower long-term capital gains rates with respect to dividends paid on shares or
ADSs.

     A U.S. Holder will not be allowed to benefit from the lower long-term
capital gains rates unless the U.S. Holder (i) holds stock for more than 60 days
during the 121-day period beginning on the date that is 60 days before the date
on which the share becomes ex-dividend (disregarding any period during which the
U.S. Holder has a diminished risk of loss with respect to such stock), and (ii)
is not under an obligation to make related payments with respect to positions in
substantially similar or related property.

     Norwegian taxes imposed on dividend distributions on our shares or ADSs
generally will be eligible for credit against the U.S. Holder's U.S. federal
income taxes. The amount of the Norwegian taxes eligible for this foreign tax
credit generally will be equal to the amount of such taxes withheld from the
dividend distributions, reduced by the amount of any refunds of such taxes
subsequently received. U.S. Holders that are eligible for benefits under the
Convention will not be entitled to a foreign tax credit for the amount of any
Norwegian taxes withheld in excess of the 15% maximum rate, and with respect to
which the holder can obtain a refund from the Norwegian taxing authorities. U.S.
Holders that are accrual basis taxpayers generally must translate Norwegian
taxes into U.S. dollars at a rate equal to the average exchange rate for the
taxable year in which the taxes accrue (except that, for taxable years beginning
after December 31,
                                        72
<PAGE>

2004, such a U.S. Holder may elect to translate Norwegian taxes using the
exchange rate at the time the taxes are paid if the U.S. Holder's functional
currency for tax purposes is not the Norwegian kroner). All U.S. Holders must
translate taxable dividend income into U.S. dollars at the spot rate on the date
received. This difference in exchange rates may reduce the U.S. dollar value of
the credits for Norwegian taxes relative to the U.S. Holder's U.S. federal
income tax liability attributable to the dividend.

     Under the foreign tax credit limitations of the Code, the foreign tax
credit can offset U.S. federal income taxes imposed on foreign-source income but
not on U.S.-source income. In addition, foreign taxes imposed on income in
certain categories specified in the Code may only be used to offset U.S. taxes
on income in the same category. Subject to special rules we describe below,
dividends we pay will generally be foreign-source income within either the
"passive income" category or the "financial services income" category, depending
on the particular U.S. Holder's circumstances. For taxable years beginning after
December 31, 2006, dividends that previously would have been within the
"financial services income" category will generally be within the "general
income" category.

     The Code contains a provision that could, in certain circumstances, cause a
portion of the dividends we pay to be treated as U.S.-source income. Even if
that provision applied to dividends we pay to a U.S. Holder, because of the
source rules contained in the Convention, no portion of such a dividend would be
recharacterized as U.S.-source income if the U.S. Holder includes the dividend
as a separate category of income for purposes of the foreign tax credit
limitation.

     If a U.S. Holder that is an individual, estate, or trust is taxed at the
lower long-term capital gains rates on dividends we pay, the Code contains a
provision that will cause a portion of any dividend eligible for this lower rate
to be treated as U.S.-source income. This provision is intended to limit the
amount of the Norwegian taxes eligible for the foreign tax credit to the amount
of U.S. tax paid by the U.S. Holder at the lower long-term capital gains rates.
U.S. Holders are advised to consult their own tax advisors when determining the
portion of any dividend that will be treated as U.S.-source income under this
provision.

     A U.S. Holder will not be allowed to claim foreign tax credits (but would
instead be allowed deductions) for foreign taxes withheld on a dividend if the
U.S. Holder has not held the shares for at least 16 days in the 31-day period
beginning 15 days before the date on which the shares become ex-dividend with
respect to such dividend.

  TAXATION OF ORDINARY DISPOSITIONS

     A U.S. Holder normally is not taxed in Norway on gains from the sale or
other disposal of our shares or ADSs. Such a holder may be subject to taxation
if the shareholding is effectively connected with a business carried out by the
shareholder through a permanent establishment in Norway. In addition, a
shareholder may be subject to taxation on gains if the shareholder is an
individual who has been a resident of Norway for income tax purposes and the
disposal takes place within five years after the calendar year in which the
shareholder ceased to be a resident of Norway. The same rules apply to gains
realized upon complete liquidation of us or upon redemption of our shares or
ADSs. Repayment in connection with a reduction of our share capital by reducing
the nominal value of the shares is, however, subject to withholding tax as a
dividend distribution, if exceeding paid-in capital.

     Under Norwegian tax law, gains from the sale or other disposal of our
shares or ADSs by a U.S. Holder who is eligible for taxation in Norway are
taxable as general income at a flat rate of 28%. Losses are deductible against
general income. The tax liability and deductibility apply irrespective of how
long the shares have been owned and the number of shares that is sold. The gain
or loss is calculated for each individual share as the difference between the
consideration received and the tax basis of the share. The tax basis of the
share is determined as the acquisition cost, adjusted for annual changes in our
taxed equity during the shareholders' ownership period. The calculation of the
change in taxed equity is based on taxable profit, reduced by taxes payable and
any dividends. If the shares disposed of have been acquired at different times,
the shares that were first acquired will be deemed as first sold. Costs incurred
in connection with the purchase and sale of shares are deductible in the year of
sale. Under the proposed amendments to the Norwegian tax law, gains from
disposal of shares would be exempted from taxation if
                                        73
<PAGE>

the shareholder is a corporate entity. Losses would not be deductible. If the
shareholder is an individual, a gain from disposal of shares would be taxable as
general income at a flat rate of 28%. The calculation of the taxable gain for
the individual would also be amended, whereby the gain would be calculated as
the difference between the consideration received and the acquisition cost,
adjusted for a "protected yield" (equal to average interest rate on five-year
bonds).

     A U.S. Holder will recognize capital gain or loss for U.S. federal income
tax purposes on a sale or other disposition of our shares or ADSs (or rights to
subscribe for our shares), including a sale or other disposition by Citibank of
shares (or rights to subscribe for shares) received as dividends on the ADSs, in
the same manner as on the sale or other disposition of any other shares held as
capital assets (or rights to acquire such shares). Such capital gain or loss
will be an amount equal to the difference between the U.S. dollar value of the
amount realized and the U.S. Holder's tax basis in the shares. Such capital gain
or loss will be long-term if the shares have been held for more than one year.
Long-term capital gains recognized by individuals, estates, and trusts are
eligible for taxation at rates not in excess of 15%. Any such gain or loss will
generally be U.S.-source income or loss.

     Regardless of the holding period of the shares or ADSs disposed, if an
individual U.S. Holder receives a dividend from us qualifying for the long-term
capital gains rates and such dividend constitutes an "extraordinary dividend,"
and the U.S. Holder subsequently recognizes a loss on the sale or exchange of
our stock, then the loss will be long-term capital loss to the extent of such
"extraordinary dividend." An "extraordinary dividend" for this purpose is a
dividend in an amount (i) greater than or equal to 10% of the taxpayer's tax
basis (or fair market value as of the day before the ex-dividend date) of the
underlying stock, aggregating dividends with ex-dividend dates within an 85-day
period, or (ii) in excess of 20% of such tax basis (or fair market value as of
the day before the ex-dividend date), aggregating dividends with ex-dividend
dates within a period of 365 days.

     A U.S. Holder will not be allowed to claim foreign tax credits (but would
instead be allowed deductions) for foreign taxes imposed on a gross basis on
gain with respect to the disposition of shares or ADSs unless the U.S. Holder
(i) holds such shares or ADSs for more than 15 days during the 31-day period
beginning on the date that is 15 days before the right to receive payment arises
(disregarding any period during which the U.S. Holder has a diminished risk of
loss with respect to such shares or ADSs) and (ii) is not under an obligation to
make related payments with respect to positions in substantially similar or
related property.

     Deposits and withdrawals of our shares in exchange for ADRs will not result
in taxable gain or loss for U.S. or Norwegian tax purposes.

  U.S. BACKUP WITHHOLDING

     Certain payments, including certain dividends and proceeds from sales of
stock, may be subject to U.S. "backup withholding" at the current 28% rate if
the recipient of such a payment fails to provide an accurate taxpayer
identification number or certification of U.S. status or fails to report all
interest and dividends required to be shown on its U.S. federal income tax
returns, or otherwise fails to establish an exemption from withholding. Any
amounts so withheld would be allowed as a credit against the recipient's U.S.
federal income tax liability for the year. Dividends we pay to a U.S. Holder
generally would be subject to these backup withholding rules.

  GIFT AND ESTATE TAX

     An individual U.S. Holder will be subject to U.S. gift and estate taxes
with respect to our shares in the same manner and to the same extent as with
respect to other types of personal property.

  NORWEGIAN TRANSFER TAX

     There is no Norwegian stock transfer tax or capital tax upon the
acquisition or subsequent disposition of our shares or ADSs.

                                        74
<PAGE>

  NORWEGIAN INHERITANCE TAX

     There is no Norwegian inheritance tax or gift tax on our shares or ADSs if
the deceased, at the time of death, or the donor at the time the gift is made,
is neither a resident nor a national of Norway. If the deceased, at the time of
death, is not a resident of Norway, but is a national of Norway, Norwegian
inheritance tax will be levied unless inheritance tax or similar tax is levied
in the country of residence and the shares are not effectively connected to a
permanent establishment in Norway. Under all circumstances, a transfer of shares
or ADSs will be subject to gift tax in Norway if the donor at the time of the
gift is a Norwegian national.

  NORWEGIAN PROPERTY TAXES OR SIMILAR TAXES

     U.S. Holders of our shares or ADSs are not subject to Norwegian property
tax or similar taxes (e.g., wealth taxes) with respect to those shares or ADSs,
unless the shareholding is effectively connected with a business carried out by
the shareholder through a permanent establishment in Norway.

DOCUMENTS ON DISPLAY

     Please read "Where You Can Find More Information" for information about
where you may read and copy documents referred to 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 annual report for information regarding our subsidiaries.

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We are exposed to certain market risks, including adverse changes in
interest rates, foreign currency exchange rates and crude oil prices, as
discussed below.

INTEREST RATE RISK

     We enter into from time to time various financial instruments, such as
interest rate swaps, to manage the impact of possible changes in interest rates.
As of December 31, 2003, we had no open interest rate swap or interest rate lock
agreements. As a result, our exposure to changes in interest rates results
primarily from our short-term and long-term debt with both fixed and floating
interest rates, from our capital lease obligations and from our UK leases. The
following table presents principal amounts and related average interest rates by
year of maturity for our debt obligations as of December 31, 2003:

<Table>
<Caption>
                             2004      2005       2006      2007      2008     THEREAFTER
                            -------   -------   --------   -------   -------   ----------
                                               (DOLLARS IN THOUSANDS)
<S>                         <C>       <C>       <C>        <C>       <C>       <C>
Debt:
  Fixed Rate..............  $10,200   $10,990   $261,920   $12,900   $14,040    $795,019
  Average Interest Rate...     8.28%     8.28%      8.01%     8.28%     8.28%       9.89%
  Variable Rate...........  $ 8,312   $ 8,391   $  1,666   $   355   $   354    $  3,039
  Average Interest Rate...     3.32%     3.32%      2.93%     2.30%     2.30%       2.30%
</Table>

     As of December 31, 2003, we had capital lease obligations of $89.3 million
payable through 2008. Interest associated with these capital lease obligations
is based on U.S. dollar LIBOR plus a margin. Accordingly, for every one
percentage point change in LIBOR, our interest expense will increase
approximately $0.8 million in 2005.

     As described under "Operating and Financial Review and
Prospects -- Liquidity and Capital Resources -- UK Leases" in Item 5 of this
annual report, we have entered into certain capital leases in the United
Kingdom. The leases are legally defeased because we have made payments to
independent third-party banks in consideration for which these banks have
assumed liability to the lessors equal to

                                        75
<PAGE>

basic rentals and termination sum obligations. The defeased rental payments are
based on assumed Sterling LIBOR rates between 8% and 9%. If actual interest
rates are greater than the assumed interest rates, we receive rental rebates.
If, on the other hand, actual interest rates are less than the assumed interest
rates, we are required to pay rentals in excess of the defeased rental payments.
As of December 31, 2003, our balance sheet reflected a liability of $48.6
million for this interest rate exposure. This liability was recorded upon our
adoption of fresh start reporting and will be amortized based on future rental
payments. During 2003, 2002 and 2001, actual interest rates were below the
assumed interest rates, and we made additional required rental payments of
approximately $1.5 million, $3.9 million and $1.5 million in the ten months
ended October 31, 2003 and the years ended December 31, 2002 and 2001,
respectively. For additional information with respect to our UK leases, please
read "Operating and Financial Review and Prospects -- Liquidity and Capital
Resources -- UK Leases" in Item 5 and notes 2 and 19 of the notes to our
consolidated financial statements in Item 18 of this annual report.

FOREIGN CURRENCY EXCHANGE RATE RISK

     We conduct business in various currencies including the Mexican peso,
Bolivian boliviano, Dubi dirham, Bangladesh taka, Kazakhstan tenge, Indian
rupee, Saudi Arabian riyal, British pound and the Norwegian kroner and are
subject to foreign currency exchange rate risk on cash flows related to sales,
expenses, financing and investing transactions in currencies other than the U.S.
dollar. As of December 31, 2002 and 2003, we did not have any open forward
exchange contracts to manage the exposure related to these risks.

     Our cash flows from operations are primarily denominated in U.S. dollars,
British pounds and Norwegian kroner. We predominantly sell our products and
services in U.S. dollars while some portion of our operating expenses are
incurred in British pounds and Norwegian kroner. We therefore typically have
higher expenses than revenue denominated in British pounds and Norwegian kroner.

     Substantially all of our debt is denominated in U.S. dollars.

COMMODITY RISK

     We operate in the worldwide crude oil markets and are exposed to
fluctuations in hydrocarbon prices, which historically have fluctuated widely in
response to changing market forces. Pertra's net production in 2003 (combined)
was 4,056,083 barrels, with an average realized price of $29.37 per barrel. In
2002 the average realized price was $27.87 per barrel. At the production level
for 2003, an average 10% change in crude oil prices would have a pre-tax effect
of approximately $12 million.

     As of December 31, 2002 and 2003, we did not have outstanding any
derivative commodity instruments. In the first half of 2004, we sold forward
950,000 barrels of our second half production at an estimated average of $30.50
per barrel.

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

     Not applicable.

                                        76
<PAGE>

                                    PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

     We hereby incorporate information called for by this item by reference to
our Form 6-Ks filed on July 2, 2003, July 18, 2003, September 11, 2003, October
10, 2003 and November 4, 2003.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF
PROCEEDS

     We hereby incorporate information called for by this item by reference to
our Form 6-Ks filed on July 29, 2003, September 11, 2003, October 10, 2003,
October 20, 2003, October 21, 2003, November 4, 2003 and November 7, 2003.

ITEM 15. CONTROLS AND PROCEDURES

     Because of the sale of the operations conducted by our Atlantis, Tigris and
PGS Production Group Ltd. (formerly Atlantic Power Group) subsidiaries in 2002
and 2003, for purposes of presenting U.S. GAAP consolidated financial statements
for the three years ended December 31, 2003, we were required to have our 2001
financial statements re-audited to reflect the businesses sold as discontinued
operations. In connection with that re-audit and the audit of our financial
statements for 2002 and 2003, we have identified various accounting errors
requiring restatement of our historical U.S. GAAP financial statements for 2001.
The nature, amounts and impact of these restatements are described in "Operating
and Financial Review and Prospects -- Restatement of Previously Issued Financial
Statements" in Item 5 of this annual report and in note 4 of the notes to our
consolidated financial statements included in Item 18 of this annual report.

     In planning and performing their audits in accordance with the standards of
the Public Company Accounting Oversight Board (United States) of our U.S. GAAP
consolidated financial statements for the two months ended December 31, 2003
(Successor), the ten months ended October 31, 2003 (Predecessor) and the years
ended December 31, 2002 and 2001 (Predecessor), and as of December 31, 2003
(Successor) and 2002 (Predecessor), our independent auditors, Ernst & Young AS
("EY"), considered our internal controls to determine auditing procedures and
noted certain matters involving internal control and its operation that they
considered to be reportable conditions under standards established by the
American Institute of Certified Public Accountants. EY reported to our Audit
Committee material weaknesses regarding various elements of our system of
internal controls. They noted weaknesses with respect to our documentation of or
adherence to accounting policies and procedures relating to significant
financial statement accounts, including the quality of support for accounting
books and records, and with respect to the quality of financial reporting and
closing of books process at the segment level. Their observations also related
to more general matters, including supervision and review control activities
within the finance and accounting organization and the adequacy of our U.S. GAAP
expertise.

     As a result of these material weaknesses and other factors, including our
2003 financial reorganization and Chapter 11 proceeding, we have not until
recently been able to prepare consolidated financial statements under U.S. GAAP
for 2001 or consolidated financial statements under U.S. GAAP for 2002 and 2003.
As a result, we did not file our annual report on Form 20-F for the year ended
December 31, 2002 and did not timely file our annual report on Form 20-F for the
year ended December 31, 2003. We have, however, been providing financial
information for these periods that has been prepared in accordance with
Norwegian GAAP.

     In connection with issuing their opinion dated June 16, 2004 on our
Norwegian GAAP consolidated financial statements for the year ended December 31,
2003, EY reported to our Board of Directors that several of the actions we
initiated as a response to the material weaknesses referenced above had not been
in effect long enough to give desired results and the quality of the closing
process for the 2003 Norwegian GAAP consolidated financial statements
demonstrated the need to complete the process of providing further improvements
and resources.

                                        77
<PAGE>

     Under the direction of our new Audit Committee and Board of Directors,
which took office in November 2003 when we emerged from Chapter 11 proceedings,
our management has taken action, including the hiring of a new Chief Financial
Officer in January 2004, to address the material weakness issues. We have
developed and are actively implementing a plan to address the matters
identified, including:

     - changing the reporting line of segment level finance staff from local
       operational managers to the Chief Financial Officer;

     - hiring new personnel with expertise in U.S. GAAP and U.S. regulations;

     - improving overall GAAP expertise throughout the accounting organization;

     - upgrading the corporate business controller function;

     - reinforcing and improving documentation, supervisory review and reporting
       procedures;

     - implementing standardized procedures manuals and training for our shared
       accounting services globally;

     - reviewing all significant accounting policies and practices, leading to
       the establishment of new and more precise accounting policies;

     - establishing and outsourcing our internal audit function in cooperation
       with the accounting firm Deloitte & Touche;

     - establishing a disclosure committee headed by our Chief Financial Officer
       and implementing revised disclosure controls and procedures; and

     - upgrading to a newer version of our financial accounting and reporting
       system and implementing that system through all of our businesses.

     With respect to new personnel, since our exit from Chapter 11 proceedings
in November 2003, we have hired:

     - a new U.S. GAAP accounting and reporting officer;

     - a new compliance officer, primarily in charge of Sarbanes-Oxley Act
       implementation and internal audit;

     - a new group business controller; and

     - additional GAAP trained personnel within our various business segments,
       including a new financial reporting controller for each of Marine
       Geophysical, Onshore and Pertra.

In addition, within Marine Geophysical, new additional financial reporting
controllers have been employed for each of the two largest regions and our
marine acquisition group. In Onshore and in our shared accounting services
group, we have increased the number of accounting personnel in key areas.

     Acting under the supervision and guidance of our Audit Committee and Board
of Directors, these new employees, together with various consultants and
contractors, have worked to address our material weaknesses, prepare financial
statements in accordance with U.S. GAAP and provide EY with support for its
re-audit of our 2001 U.S. GAAP financial statements and its audits of our 2002
and 2003 U.S. GAAP financial statements. We believe that our progress to date in
addressing our material weaknesses has been hampered by a combination of
factors, including (a) our deteriorating financial condition in late 2002 and
early 2003 that led ultimately to our financial reorganization in 2003 through a
Chapter 11 proceeding, (b) substantial changes in our accounting and financial
reporting personnel preceding and during the Chapter 11 process and (c) the
substantial effort, complexity and long period of time associated with
finalizing the re-audit and audits of our U.S. GAAP financial statements
discussed above, including the application of "fresh start" reporting in
accordance with SOP 90-7.

                                        78
<PAGE>

     Our management, with the oversight of our Audit Committee and Board of
Directors, is committed to remediating the remaining material weaknesses and
deficiencies in our internal control over financial reporting as expeditiously
as possible. We believe that the actions we have taken have significantly
improved the quality of our internal control over financial reporting. As of the
date of this annual report, we are in the process of completing some of the
actions under the established plan and assessing the effectiveness of actions
implemented to date under the plan to identify any appropriate changes or
additional activities. We expect the following significant activities will
extend into the first quarter of 2005, after which we believe our current plan
to address previously identified material weaknesses will be substantially
completed and in effect:

     - completion of the upgrade and extended application of our financial
       reporting system and training of system users;

     - completion of the improvement of our accounting policies and procedures
       manual and related training of finance function personnel;

     - completion and implementation of service level agreements between our
       global shared accounting services and business units; and

     - completion of improvement of certain procedures related to documentation
       and work-flow.

After taking these actions, and as we prepare for implementation of the
assessment and reporting on internal control over financial reporting under
Section 404 of the Sarbanes-Oxley Act of 2002 as described below, our management
will reassess the effectiveness of our disclosure controls and procedures and
our internal control over financial reporting and assess the adequacy and
effectiveness of the remedial actions discussed above. In addition, in
connection with their audit of our 2004 financial statements, we expect our
independent auditors to perform a similar assessment of the effectiveness of the
remedial actions we have taken by year end 2004.

     As required by SEC Rule 13a-15(b), we have carried out an evaluation, under
the supervision and with the participation of our management, including our
Chief Executive Officer and our Chief Financial Officer, of the effectiveness of
our disclosure controls and procedures as of December 31, 2003, the end of the
period covered by this annual report. Based on that evaluation, our Chief
Executive Officer and our Chief Financial Officer concluded that, as of December
31, 2003, our disclosure controls and procedures were not effective to ensure
that information required to be disclosed by us in the reports we file or submit
under the U.S. Securities Exchange Act of 1934 was timely recorded, processed,
summarized and reported. In addressing the material weaknesses and deficiencies
discussed above, we have significantly expanded our disclosure controls and
procedures to include additional procedures and analysis to ensure our
disclosure controls and procedures were effective in connection with the
preparation of this annual report and the financial statements included herein.

     Beginning with the year ending December 31, 2005, Section 404 of the
Sarbanes-Oxley Act will require us to include an internal control report of
management with our annual report on Form 20-F. The internal control report must
contain (1) a statement of management's responsibility for establishing and
maintaining adequate internal control over financial reporting for us, (2) a
statement identifying the framework used by management to conduct the required
evaluation of the effectiveness of our internal control over financial
reporting, (3) management's assessment of the effectiveness of our internal
control over financial reporting as of the end of our most recent fiscal year,
including a statement as to whether or not our internal control over financial
reporting is effective, and (4) a statement that our independent auditors have
issued an attestation report on management's assessment of our internal control
over financial reporting.

     As described above, we have made and continue to make significant changes
in our internal control over financial reporting, changes which began in late
2003 and have continued into 2004. We expect to continue to make changes in our
internal control over financial reporting from time to time during our
preparation for compliance with Section 404 of the Sarbanes-Oxley Act. The
changes taken to date have materially affected and improved, and we believe
these and additional changes we expect to make in the
                                        79
<PAGE>

future are reasonably likely to materially affect and improve, our internal
control over financial reporting going forward. In addition, these changes have
been specifically designed to enable us to timely meet the requirements of
Section 404 of the Sarbanes-Oxley Act. Although, as described above, we have
introduced additional procedures and analysis to ensure our disclosure controls
and procedures were effective in connection with the preparation of this annual
report and the financial statements included herein, as of the date of this
annual report we have not eliminated all material weaknesses described above.

     In addition, as we implement remaining changes in our internal controls and
as we prepare to address requirements under the Sarbanes-Oxley Act, we may
identify additional deficiencies in our system of internal control over
financial reporting that either individually or in the aggregate may represent a
material weakness requiring additional remedial efforts.

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

     Our board of directors has determined that each of Francis Gugen, Anthony
Tripodo and Harald Norvik meets the definition of an audit committee financial
expert, as that term is defined for purposes of Item 16A of Form 20-F, and that
each is independent, as that term is defined by the New York Stock Exchange.

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 similar functions. We have filed the code as an
exhibit to this annual report and posted it under the "About PGS" section of our
internet website at www.pgs.com.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

     Under our Audit Committee Charter, the Audit Committee is responsible
(subject to ratification by the Board of Directors) for:

     - pre-approving all auditing services and permitted non-audit services to
       be provided by our independent auditors and for observing applicable
       limitations on engaging the independent auditors to perform the specific
       non-audit services restricted by law or regulations; and

     - to the extent it deems necessary or appropriate, to retain and compensate
       independent legal, accounting or other advisors.

     Under our pre-approval policy, the Audit Committee is required to
preapprove all audit, review or attest engagements and permissible non-audit
services to be performed by our independent auditors, subject to, and in
compliance with, the de minimis exception for non-audit services described in
applicable provisions of the Securities Exchange Act of 1934 and applicable SEC
rules. All services provided by EY in 2003 were preapproved by the Audit
Committee.

                                        80
<PAGE>

     Aggregate fees through October 31, 2004 for professional services rendered
by EY, including reimbursement of out-of-pocket expenses, related to 2003, 2002
and 2001 were as follows:

<Table>
<Caption>
                                                              2003     2002     2001
                                                             ------   ------   ------
                                                                  (IN THOUSANDS)
<S>                                                          <C>      <C>      <C>
Audit fees(1)..............................................  $5,434   $2,228   $6,161
Audit-related fees(2)......................................     114      455       --
Fees for tax services(3)...................................     182       51       --
All other fees(4)..........................................     541      540       --
                                                             ------   ------   ------
Total......................................................  $6,271   $3,274   $6,161
                                                             ======   ======   ======
</Table>

---------------

(1) Audit fees consisted of fees for audit and re-audit services, which related
    to the consolidated audit, quarterly reviews, statutory audits, accounting
    consultations, subsidiary audits and related matters, and fees for audit of
    fresh start accounting.

(2) Audit-related fees consisted of fees for agreed upon procedures and other
    attestation services.

(3) Fees for tax services consisted of fees for tax services, tax filing and
    compliance and tax planning and reorganization.

(4) Other fees consisted of fees for assistance in connection with
    restructuring, refinancing and due diligence performed by banks in
    connection with our financial restructuring in 2003.

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.

                                        81
<PAGE>

                                    PART III

ITEM 17. FINANCIAL STATEMENTS

     Not applicable.

ITEM 18. FINANCIAL STATEMENTS

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<Table>
<Caption>
                                                               PAGE
                                                               ----
<S>                                                            <C>
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, 2003
  (Successor) and 2002 (Predecessor)........................   F-3
Consolidated Statements of Operations for the two months
  ended December 31, 2003 (Successor), the ten months ended
  October 31, 2003 and the years ended December 31, 2002 and
  2001 (Predecessor)........................................   F-4
Consolidated Statements of Cash Flows for the two months
  ended December 31, 2003 (Successor), the ten months ended
  October 31, 2003 and the years ended December 31, 2002 and
  2001 (Predecessor)........................................   F-5
Consolidated Statements of Changes in Shareholders' Equity
  for the two months ended December 31, 2003 (Successor),
  the ten months ended October 31, 2003 and the years ended
  December 31, 2002 and 2001 (Predecessor)..................   F-6
Notes to Consolidated Financial Statements..................   F-7
</Table>

     We specifically incorporate by reference in response to this item the
auditor's report, the consolidated financial statements and the notes to the
consolidated financial statements appearing on pages F-2 through F-61.

                                        82
<PAGE>

ITEM 19. EXHIBITS

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
           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 Ex-
                            hibit(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 Nos. 33-61500 and 333-10856))
           2.4           -- Indenture dated as of November 5, 2003, among the
                            Company, each of the guarantors named therein and Law
                            Debenture Trust Company of New York, as trustee (the
                            "Trustee")
           2.5           -- First Supplemental Indenture, dated as of November 5,
                            2003, among the Company, each of the guarantors named
                            therein and the Trustee
           2.6           -- Second Supplemental Indenture, dated as of June 4, 2004,
                            among the Company, each of the guarantors named therein
                            and the Trustee
</Table>

        The Company and its consolidated subsidiaries are party to several debt
        instruments under which the total amount of securities authorized does
        not exceed 10% of the total assets of the Company and its subsidiaries
        on a consolidated basis. Pursuant to paragraph 2(b)(i) of the
        instructions to the exhibits to Form 20-F, the Company agrees to furnish
        a copy of such instruments to the SEC upon request.

<Table>
<C>                      <S>
           4.1           -- Employment agreement dated November 4, 2002 between the
                            Company and Svein Rennemo (the "Employment Agreement")
           4.2           -- Addendum to the Employment Agreement dated June 8, 2004
                            between the Company and Svein Rennemo
           4.3           -- 2004 CEO Bonus Scheme
           8.1           -- Subsidiaries (included in Item 4 of the annual report)
          11.1           -- Code of Conduct
          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
          15.2           -- Remuneration Committee Charter
</Table>

                                        83
<PAGE>

                                   SIGNATURES

     The registrant hereby certifies that it meets all of the requirements for
filing on Form 20-F and that it has duly caused and authorized the undersigned
to sign this annual report on its behalf.

                                          PETROLEUM GEO-SERVICES ASA

                                          BY:     /s/ GOTTFRED LANGSETH
                                            ------------------------------------
                                                     GOTTFRED LANGSETH
                                                  Chief Financial Officer

Date: November 16, 2004

                                        84
<PAGE>

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<Table>
<Caption>
                                                               PAGE
                                                               ----
<S>                                                            <C>
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, 2003
  (Successor) and 2002 (Predecessor)........................   F-3
Consolidated Statements of Operations for the two months
  ended December 31, 2003 (Successor), the ten months ended
  October 31, 2003 and the years ended December 31, 2002 and
  2001 (Predecessor)........................................   F-4
Consolidated Statements of Cash Flows for the two months
  ended December 31, 2003 (Successor), the ten months ended
  October 31, 2003 and the years ended December 31, 2002 and
  2001 (Predecessor)........................................   F-5
Consolidated Statements of Changes in Shareholders' Equity
  for the two months ended December 31, 2003 (Successor),
  the ten months ended October 31, 2003 and the years ended
  December 31, 2002 and 2001 (Predecessor)..................   F-6
Notes to Consolidated Financial Statements..................   F-7
</Table>

                                       F-1
<PAGE>

            REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF
PETROLEUM GEO-SERVICES ASA:

     We have audited the accompanying consolidated balance sheets of Petroleum
Geo-Services ASA and subsidiaries as of December 31, 2003 (Successor) and 2002
(Predecessor), and the related consolidated statements of operations, changes in
shareholders' equity (deficit), and cash flows for the two months ended December
31, 2003 (Successor) and ten months ended October 31, 2003 (Predecessor) and for
the years ended December 31, 2002 and 2001 (Predecessor). These financial
statements are the responsibility of the Company's Board of Directors and
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

     We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Petroleum Geo-Services ASA
and subsidiaries as of December 31, 2003 (Successor) and 2002 (Predecessor), and
the consolidated results of their operations and their cash flows for the two
months ended December 31, 2003 (Successor), the ten months ended October 31,
2003 (Predecessor) and the years ended December 31, 2002 and 2001 (Predecessor)
in conformity with U.S. generally accepted accounting principles.

     As discussed in Note 3 to the consolidated financial statements, the
Company emerged from bankruptcy and, effective November 1, 2003, adopted
fresh-start reporting pursuant to American Institute of Certified Public
Accountants Statement of Position 90-7, "Financial Reporting by Entities in
Reorganization Under the Bankruptcy Code". As a result, the consolidated
financial statements of the Successor are presented on a different basis than
those of the Predecessor and, therefore, are not comparable.

     As discussed in Note 2 of the consolidated financial statements, the
Predecessor changed its accounting principles to adopt, as of January 1, 2002,
the provisions of Statement of Financial Accounting Standards No. 142, "Goodwill
and Other Intangible Assets" and Statement of Financial Accounting Standards No.
144 "Accounting for the Impairment or Disposal of Long-Lived Assets", and, as of
January 1, 2003, the provisions of Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations."

     As more fully described in Note 4, the 2001 financial statements have been
restated to correct certain errors in the application of U.S. generally accepted
accounting principles.

ERNST & YOUNG AS

Oslo, Norway
November 12, 2004

                                       F-2
<PAGE>

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                              SUCCESSOR     PREDECESSOR
                                                               COMPANY        COMPANY
                                                              ----------    -----------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------    -----------
                                                              (IN THOUSANDS OF DOLLARS,
                                                                 EXCEPT SHARE DATA)
<S>                                                           <C>           <C>
                                        ASSETS
Cash and cash equivalents...................................  $  105,225    $    91,617
Restricted cash.............................................      41,123         21,219
Accounts receivable, net....................................     127,706        169,136
Unbilled and other receivables..............................      47,864         44,510
Deferred tax assets.........................................          --          1,193
Other current assets........................................      62,610         52,658
Assets of discontinued operations...........................          --         68,768
                                                              ----------    -----------
          Total current assets..............................     384,528        449,101
Multi-client library, net...................................     408,005        583,859
Property and equipment, net.................................   1,060,183      1,702,348
Oil and natural gas assets, net.............................      36,426         37,040
Restricted cash.............................................      10,014         10,014
Investments in associated companies.........................       8,070         10,458
Intangible assets, net......................................      52,609          5,337
Other long-lived assets.....................................      37,525         41,580
                                                              ----------    -----------
          Total assets......................................  $1,997,360    $ 2,839,737
                                                              ==========    ===========

                         LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt and current portion of long-term debt.......  $   18,512    $ 1,005,061
Current portion of capital lease obligations................      19,963         25,332
Debt and other liabilities of discontinued operations.......          --         21,523
Accounts payable............................................      56,318         55,514
Accrued expenses............................................     147,336        219,544
Deferred tax liabilities....................................       2,166             --
Income taxes payable........................................      17,946          4,703
                                                              ----------    -----------
          Total current liabilities.........................     262,241      1,331,677
Long-term debt..............................................   1,108,674      1,320,339
Long-term capital lease obligations.........................      63,473         88,795
Other long-term liabilities.................................     197,663        124,196
Deferred tax liabilities....................................      10,738         24,405
                                                              ----------    -----------
          Total liabilities.................................   1,642,789      2,889,412
                                                              ----------    -----------
Commitments and contingencies (Note 19)
Minority interest in consolidated subsidiaries..............         937            257
Guaranteed preferred beneficial interest in PGS junior
  subordinated debt securities..............................          --        142,322
Shareholders' equity (deficit):
  Common stock; 20,000,000 shares authorized, issued and
     outstanding, par value NOK 30, at December 31, 2003 and
     123,345,987 shares authorized, 103,345,987 shares
     issued and outstanding, par value NOK 5, at December
     31, 2002...............................................      85,714         71,089
  Additional paid-in capital................................     277,427      1,225,115
  Accumulated deficit.......................................      (9,953)    (1,458,097)
  Accumulated other comprehensive income (loss).............         446        (30,361)
                                                              ----------    -----------
          Total shareholders' equity (deficit)..............     353,634       (192,254)
                                                              ----------    -----------
          Total liabilities and shareholders' equity........  $1,997,360    $ 2,839,737
                                                              ==========    ===========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                       F-3
<PAGE>

                     CONSOLIDATED STATEMENTS OF OPERATIONS

<Table>
<Caption>
                                                                SUCCESSOR
                                                                 COMPANY                   PREDECESSOR COMPANY
                                                              -------------   ---------------------------------------------
                                                               TWO MONTHS      TEN MONTHS
                                                                  ENDED           ENDED         YEARS ENDED DECEMBER 31,
                                                              DECEMBER 31,     OCTOBER 31,    -----------------------------
                                                                  2003            2003            2002            2001
                                                              -------------   -------------   -------------   -------------
                                                                                                               (RESTATED)
                                                               (IN THOUSANDS OF DOLLARS, EXCEPT PER SHARE AND SHARE DATA)
<S>                                                           <C>             <C>             <C>             <C>
Revenues Services...........................................   $   162,827    $    849,767    $  1,010,534    $    893,230
Revenues Products...........................................         9,544         112,097          32,697              --
                                                               -----------    ------------    ------------    ------------
         Total Revenues.....................................       172,371         961,864       1,043,231         893,230
                                                               -----------    ------------    ------------    ------------
Cost of sales Services......................................        90,700         454,396         530,386         557,074
Cost of sales Products......................................         6,254          33,382          10,801              --
Depreciation and amortization...............................        55,699         301,576         367,503         336,480
Research and development costs..............................           598           2,024           2,766           3,752
Selling, general and administrative costs...................         7,366          44,326          53,426          61,999
Impairment of long-lived assets.............................            --          95,011         558,471          12,686
Other operating (income) expense, net.......................         1,052          21,324           8,487        (125,559)
                                                               -----------    ------------    ------------    ------------
         Total operating expenses...........................       161,669         952,039       1,531,840         846,432
                                                               -----------    ------------    ------------    ------------
Operating profit (loss).....................................        10,702           9,825        (488,609)         46,798
Other income (expense):
  Income (loss) from associated companies...................           200             774         (11,501)           (690)
  Interest expense..........................................       (16,870)        (98,957)       (153,301)       (151,624)
  Other financial items, net................................        (4,264)         (1,472)         33,792          (6,269)
                                                               -----------    ------------    ------------    ------------
                                                                   (10,232)        (89,830)       (619,619)       (111,785)
Reorganization items:
  Gain on debt discharge....................................            --       1,253,851              --              --
  Fresh-start adoption......................................            --        (532,268)             --              --
  Cost of reorganization....................................        (3,325)        (52,334)         (3,616)             --
Minority expense (benefit)..................................           110             570             778              (4)
Income tax expense (benefit)................................        (3,849)         21,911         185,890          28,344
                                                               -----------    ------------    ------------    ------------
  Income (loss) from continuing operations before cumulative
    effect of change in accounting principles...............        (9,818)        556,938        (809,903)       (140,125)
Loss from discontinued operations, net of tax...............          (135)         (2,282)       (201,137)        (32,354)
                                                               -----------    ------------    ------------    ------------
  Income (loss) before cumulative effect of change in
    accounting principles...................................        (9,953)        554,656      (1,011,040)       (172,479)
Cumulative effect of change in accounting principles, net of
  tax.......................................................            --           2,389        (163,638)             --
                                                               -----------    ------------    ------------    ------------
         Net income (loss)..................................   $    (9,953)   $    557,045    $ (1,174,678)   $   (172,479)
                                                               ===========    ============    ============    ============
Basic and diluted income (loss) per share from continuing
  operations................................................   $     (0.49)   $       5.39    $      (7.84)   $      (1.36)
Loss from discontinued operations, net of tax...............         (0.01)          (0.02)          (1.95)          (0.32)
Cumulative effect of change in accounting principle, net of
  tax.......................................................            --            0.02           (1.58)             --
                                                               -----------    ------------    ------------    ------------
Basic and diluted net income (loss) per share...............   $     (0.50)   $       5.39    $     (11.37)   $      (1.68)
                                                               ===========    ============    ============    ============
Weighted average basic and diluted shares outstanding.......    20,000,000     103,345,987     103,345,987     102,768,283
                                                               ===========    ============    ============    ============
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                       F-4
<PAGE>

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                            SUCCESSOR
                                                             COMPANY               PREDECESSOR COMPANY
                                                           ------------   --------------------------------------
                                                            TWO MONTHS    TEN MONTHS
                                                              ENDED          ENDED      YEARS ENDED DECEMBER 31,
                                                           DECEMBER 31,   OCTOBER 31,   ------------------------
                                                               2003          2003          2002          2001
                                                           ------------   -----------   -----------   ----------
                                                                                                      (RESTATED)
                                                                         (IN THOUSANDS OF DOLLARS)
<S>                                                        <C>            <C>           <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income (loss)......................................    $ (9,953)    $   557,045   $(1,174,678)  $(172,479)
  Adjustments to reconcile net income (loss) to net cash
    provided by operating activities:
    Depreciation and amortization charged to expense.....      55,699         301,576       367,503     336,480
    Non-cash impairments, loss (gain) sale of
      subsidiaries and change in accounting principles,
      net................................................          32          92,622       935,244     (82,537)
    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..........................................          --          13,152            --          --
    Cash effects related to discontinued operations......         157           3,185         5,540      (3,274)
    Provision for deferred income taxes..................      (5,801)         (1,918)      171,771      25,702
    (Increase) decrease in accounts receivable, net......      34,582           6,848       (22,628)    (31,030)
    Increase (decrease) in accounts payable..............      19,391         (18,587)      (10,814)     (1,764)
    Loss on sale of assets...............................          --           6,193        11,750         294
    Other items..........................................     (35,761)        (51,674)        9,319      46,686
                                                             --------     -----------   -----------   ---------
         Net cash provided by operating activities.......      58,346         188,676       293,007     118,078
                                                             --------     -----------   -----------   ---------
CASH FLOWS (USED IN) PROVIDED BY INVESTING ACTIVITIES:
  Investment in multi-client library.....................      (9,461)        (81,142)     (151,590)   (174,028)
  Capital expenditures...................................     (15,985)        (42,065)      (56,735)   (147,536)
  Capital expenditures on discontinued operations........          --            (118)      (77,364)    (54,467)
  Sale of subsidiaries...................................          --          50,115        20,222     175,000
  Other items, net.......................................         357           3,478        (9,030)    (19,485)
                                                             --------     -----------   -----------   ---------
         Net cash used in investing activities...........     (25,089)        (69,732)     (274,497)   (220,516)
                                                             --------     -----------   -----------   ---------
CASH FLOWS (USED IN) PROVIDED BY FINANCING ACTIVITIES:
  Net proceeds -- issuance of long-term debt.............          --              --            --     234,285
  Net proceeds -- issuance of common stock, including
    stock option exercises...............................          --              --            --         816
  Repayment of long-term debt............................      (4,850)        (70,496)     (340,809)    (88,694)
  Principal payments under capital leases................      (3,025)        (22,352)      (19,839)    (11,816)
  Net increase (decrease) in bank facility and short-term
    debt.................................................          --             (48)      335,348      (5,667)
  Net (payments) receipts under tax equalization swap
    contracts............................................          --              --         9,566     (64,575)
  Net (increase) decrease in restricted cash.............       3,824         (23,728)        1,602      (7,497)
  Other items, net.......................................     (17,932)             --         8,098          --
                                                             --------     -----------   -----------   ---------
         Net cash (used in) provided by financing
           activities....................................     (21,983)       (116,624)       (6,034)     56,852
                                                             --------     -----------   -----------   ---------
  Effect of exchange rate changes on cash................          --              14           537         (93)
                                                             --------     -----------   -----------   ---------
  Net increase (decrease) in cash and cash equivalents...      11,274           2,334        13,013     (45,679)
  Cash and cash equivalents at beginning of period.......      93,951          91,617        78,604     124,283
                                                             --------     -----------   -----------   ---------
         Cash and cash equivalents at end of period......    $105,225     $    93,951   $    91,617   $  78,604
                                                             ========     ===========   ===========   =========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.

          Supplementary cash flow information is included in note 27.

                                       F-5
<PAGE>

      CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (DEFICIT)
<Table>
<Caption>

                                           COMMON STOCK          ADDITIONAL
                                     -------------------------     PAID-IN     ACCUMULATED
                                        NUMBER       PAR VALUE     CAPITAL       DEFICIT
                                     -------------   ---------   -----------   -----------
                                       (IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
<S>                                  <C>             <C>         <C>           <C>
PREDECESSOR COMPANY:
Balance at December 31, 2000, as
  restated.........................    102,347,987   $ 70,542    $ 1,215,884   $  (109,863)
  Comprehensive loss:
    Net loss.......................                                               (172,479)
    Other comprehensive loss.......                                                     --
                                                                               -----------
    Total comprehensive loss.......                                               (172,479)
  Issuance of common stock.........        900,000        493          8,558            --
  Exercise of stock options........         98,000         54            673
                                     -------------   --------    -----------   -----------
Balance at December 31, 2001, as
  restated.........................    103,345,987     71,089      1,225,115      (282,342)
  Comprehensive income (loss):
    Net loss.......................                                             (1,174,678)
    Other comprehensive income
      (loss).......................                                                     --
                                                                               -----------
    Total comprehensive income
      (loss).......................                                             (1,174,678)
    Dividends to minority
      interest.....................                                                 (1,077)
                                     -------------   --------    -----------   -----------
Balance at December 31, 2002.......    103,345,987     71,089      1,225,115    (1,458,097)
  Comprehensive income (loss):
    Net income.....................                                                557,045
    Other comprehensive income
      (loss).......................                                                     --
                                                                               -----------
    Total comprehensive income
      (loss).......................                                                557,045
Reorganization items...............   (103,345,987)   (71,089)    (1,225,115)      901,052
                                     -------------   --------    -----------   -----------
Balance at October 31, 2003........             --   $     --    $        --   $        --
                                     =============   ========    ===========   ===========
SUCCESSOR COMPANY:
  Issuance of common stock.........     20,000,000   $ 85,714    $   277,427   $        --
  Comprehensive income (loss):.....
    Net loss.......................                                                 (9,953)
    Other comprehensive income
      (loss).......................                                                     --
                                                                               -----------
    Total comprehensive income
      (loss).......................                                                 (9,953)
                                     -------------   --------    -----------   -----------
Balance at December 31, 2003.......     20,000,000   $ 85,714    $   277,427   $    (9,953)
                                     =============   ========    ===========   ===========

<Caption>
                                                ACCUMULATED OTHER
                                           COMPREHENSIVE INCOME (LOSS)
                                     ---------------------------------------
                                       FOREIGN                  ACCUMULATED
                                      CURRENCY      PENSION        OTHER
                                     TRANSLATION    MINIMUM    COMPREHENSIVE   SHAREHOLDERS'
                                     ADJUSTMENTS   LIABILITY   INCOME (LOSS)      EQUITY
                                     -----------   ---------   -------------   -------------
                                        (IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
<S>                                  <C>           <C>         <C>             <C>
PREDECESSOR COMPANY:
Balance at December 31, 2000, as
  restated.........................   $(30,858)     $    --      $(30,858)      $ 1,145,705
  Comprehensive loss:
    Net loss.......................         --           --            --          (172,479)
    Other comprehensive loss.......     (2,762)        (346)       (3,108)           (3,108)
                                      --------      -------      --------       -----------
    Total comprehensive loss.......     (2,762)        (346)       (3,108)         (175,587)
  Issuance of common stock.........         --           --            --             9,051
  Exercise of stock options........                                    --               727
                                      --------      -------      --------       -----------
Balance at December 31, 2001, as
  restated.........................    (33,620)        (346)      (33,966)          979,896
  Comprehensive income (loss):
    Net loss.......................         --           --            --        (1,174,678)
    Other comprehensive income
      (loss).......................      7,195       (3,668)        3,527             3,527
                                      --------      -------      --------       -----------
    Total comprehensive income
      (loss).......................      7,195       (3,668)        3,527        (1,171,151)
    Dividends to minority
      interest.....................         78           --            78              (999)
                                      --------      -------      --------       -----------
Balance at December 31, 2002.......    (26,347)      (4,014)      (30,361)         (192,254)
  Comprehensive income (loss):
    Net income.....................         --           --            --           557,045
    Other comprehensive income
      (loss).......................      1,580       (3,230)       (1,650)           (1,650)
                                      --------      -------      --------       -----------
    Total comprehensive income
      (loss).......................      1,580       (3,230)       (1,650)          555,395
Reorganization items...............     24,767        7,244        32,011          (363,141)
                                      --------      -------      --------       -----------
Balance at October 31, 2003........   $     --      $    --      $     --       $        --
                                      ========      =======      ========       ===========
SUCCESSOR COMPANY:
  Issuance of common stock.........   $     --      $    --      $     --       $   363,141
  Comprehensive income (loss):.....                                                      --
    Net loss.......................         --           --            --            (9,953)
    Other comprehensive income
      (loss).......................        446           --           446               446
                                      --------      -------      --------       -----------
    Total comprehensive income
      (loss).......................        446           --           446            (9,507)
                                      --------      -------      --------       -----------
Balance at December 31, 2003.......   $    446      $    --      $    446       $   353,634
                                      ========      =======      ========       ===========
</Table>

The Company's ability to pay dividends is limited to free equity as defined in
Norwegian corporate law and measured on the basis of the unconsolidated
financial statements of the parent company, PGS ASA, as prepared in accordance
with generally accepted accounting principles in Norway. At December 31, 2003,
the Company had no free equity available for payment of dividends to
shareholders.

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                       F-6
<PAGE>

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- GENERAL INFORMATION ABOUT THE COMPANY AND BASIS OF PRESENTATION

     Petroleum Geo-Services ASA ("PGS ASA") is a public limited liability
company established under the laws of the Kingdom of Norway in 1991. Unless
stated otherwise, references herein to the "Company" and "PGS" refer to
Petroleum Geo-Services ASA and its majority-owned subsidiaries and affiliates,
companies in which it has and controls a majority voting interest (see Note 2
regarding adoption of new accounting requirements which affect the Company's
consolidation).

     PGS is a technologically focused oilfield services company principally
involved in providing geophysical services worldwide and providing floating
production services in the North Sea. Globally, it provides a broad range of
geophysical and reservoir services, including seismic data acquisition,
processing and interpretation and field evaluation. In the North Sea, the
Company owns and operates four floating production, storage and offloading
("FPSO") vessels. It also owns a small oil and natural gas company that produces
oil and natural gas from licenses on the Norwegian Continental Shelf. The
Company's headquarters are at Lysaker, Norway.

     The Company considers its primary basis of accounting to be US generally
accepted accounting principles ("US GAAP"), and has prepared these consolidated
financial statements under those principles. PGS is also required to prepare and
publish statutory accounts in Norway using Norwegian generally accepted
accounting principles ("Norwegian GAAP"). Norwegian GAAP differs materially from
US GAAP. In 2002 and early 2003, the Company sold certain businesses, which
under US GAAP required the Company to restate its previously issued historical
financial statements for the year ended December 31, 2001, so that the sold
businesses are reported as discontinued operations and not included in income
from continuing operations. The Company's previously issued consolidated
financial statements for the year ending December 31, 2001 had been audited by
an independent accounting firm that has since been dissolved. As a result, PGS
was required to have its successor independent auditors "re-audit" its 2001
consolidated financial statements. In connection with its re-audit and the audit
of 2002 and 2003, the Company identified various accounting errors requiring
further restatements to the previously published historical US GAAP financial
statements for the year ended December 31 2001. These errors and restatements
are described more fully in Note 4.

     On July 29, 2003, PGS ASA filed a voluntary petition for protection under
Chapter 11 of the US Bankruptcy Code. The filing was based on a financial
restructuring plan that was pre-approved by a majority of the Company's
creditors and a group of its largest shareholders. The Company emerged from
Chapter 11 on November 5, 2003, and adopted "fresh-start" reporting as required
under the provisions of AICPA Statement of Position ("SOP") 90-7, "Financial
Reporting by Entities in Reorganization under the Bankruptcy Code," effective
November 1, 2003. Adoption of fresh-start reporting results in companies
reflecting the fair value of the business emerging from bankruptcy (the
"reorganization value") in the post fresh start financial statements, and is
required when the holders of the voting common shares immediately before the
filing and confirmation of the reorganization plan received less than 50% of the
voting shares of the emerging company and when the company's reorganization
value is less than its post-petition liabilities and allowed claims. Since these
conditions were met, the Company adopted fresh-start reporting, and as a result,
in these consolidated financial statements, the terms "Successor" and "Successor
Company" refer to PGS' financial statements subsequent to the emergence from
Chapter 11 and the terms "Predecessor" and "Predecessor Company" refer to PGS'
financial statements for periods up to the emergence from Chapter 11 including
the effect of the reorganization plan. The adoption of fresh-start reporting
reflects the Company's reorganization value as its new basis in accounting, new
accounting pronouncements it was required to adopt with fresh start reporting,
and changes in certain of its accounting policies. The Company's financial
information in Successor Company periods should not be compared to financial
information from Predecessor Company periods as they are not comparable.

                                       F-7
<PAGE>

NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  FRESH START REPORTING.

     In connection with the adoption of fresh start reporting effective November
1, 2003, the Company adopted new accounting policies for certain transactions
and activities, as further described in the individual descriptions of these
policies 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 connection with yard stay and steaming of vessels will be 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 seismic acquisition vessels and FPSOs,
other than the Petrojarl I, from 30 to 25 years.

  USE OF ESTIMATES.

     The preparation of financial statements in accordance with US GAAP requires
management to make estimates, assumptions and judgments that affect the reported
amounts of assets and liabilities and the disclosure of contingent liabilities.
In many circumstances, the ultimate outcome related to the estimates,
assumptions and judgments may not be known for several years after the
preparation of the financial statements. Actual amounts may differ materially
from these estimates due to changes in general economic conditions, changes in
laws and regulations, changes in future operating plans and the inherent
imprecision associated with estimates.

  CONSOLIDATION AND EQUITY INVESTMENTS.

     The Company prepares its consolidated financial statements in accordance
with US GAAP. The consolidated financial statements include Petroleum
Geo-Services ASA, its wholly owned and majority-owned subsidiaries that it
controls, and variable interest entities for which it is the primary
beneficiary. All inter-company transactions and balances have been eliminated in
consolidation. In those cases where the subsidiaries are not wholly-owned, the
minority interests are separately presented in the consolidated statements of
operations and consolidated balance sheets.

     Investments in associated companies in which the Company has an ownership
interest equal to or greater than 20% but equal to or less than 50%, and where
the Company has the ability to exercise significant influence are accounted for
using the equity method. All equity investments for which the equity securities
do not have readily determinable fair values and for which the Company does not
have the ability to exercise significant influence are accounted for under the
cost method.

     The Company periodically reviews its investments to determine if a loss in
value has occurred that is other-than-temporary. PGS considers all available
information, including the recoverability of its investment, the earnings and
near-term prospects of the investee company, factors related to the industry,
conditions of the investee company and the ability, if any, to influence the
management of the investee company.

  CASH AND CASH EQUIVALENTS.

     The carrying amounts of cash and cash equivalents approximate fair value.
Cash and cash equivalents include demand deposits and all highly liquid
financial instruments purchased with maturities of three months or less.

                                       F-8
<PAGE>

     Cash and cash equivalents that are restricted from the Company's use are
disclosed separately in the consolidated balance sheets and are classified as
current or long-term depending on the nature of the restrictions. Such
restrictions primarily relate to bid bonds, employee tax withholdings,
restricted deposits under contracts, and cash in our wholly owned captive
insurance company. During 2003 the Company had increased balances of restricted
cash related to bid bonds, which amounted to $27.3 million at December 31, 2003
compared to zero at December 31, 2002.

  FOREIGN CURRENCY TRANSLATION.

     The Company's reporting currency is the US dollar ("dollar") as it is the
functional currency for substantially all of its operations throughout the
world.

     The financial statements of non-US subsidiaries using their respective
local currency as their functional currency are translated using the current
exchange rate method. Under the current exchange rate method, assets and
liabilities are translated at the rate of exchange in effect at period end;
share par value and paid-in capital are translated at historical exchange rates;
and revenue and expenses are translated at the average rates of exchange in
effect during the period. Translation adjustments, net of tax, are recorded as a
separate component of shareholders' equity.

     The exchange rate between the Norwegian Kroner and dollar at December 31,
2003 and 2002 was NOK 6.79 per dollar and NOK 7.02 per dollar, respectively. The
Predecessor recorded $4.3 million, $10.9 million and $1.7 million in net foreign
exchange losses, exclusive of the effects of the tax equalization swap contracts
(see Note 17), for the ten months ended October 31, 2003 and for the years ended
December 31, 2002 and 2001, respectively. The Successor recorded $5.2 in net
foreign exchange losses in the two-month period ended December 31, 2003. At
November 10, 2004 the exchange rate between the Norwegian Kroner and dollar was
NOK 6.30 per dollar.

  OPERATING AND CAPITAL LEASES.

     The Company has significant operating lease arrangements and several
capital lease arrangements (mainly for its UK leases (described below) and land
seismic equipment). The Company accounts for capital lease arrangements as if it
had acquired the assets and correspondingly records as capital lease obligation
an amount equal to the lesser of the asset's fair market value or the present
value of the future lease payments. The assets are depreciated over their
expected useful lives or the related lease terms, whichever is shorter.
Depreciation expense associated with assets under capital leases is included
with depreciation and amortization of all other assets in the consolidated
statement of operations.

  UK LEASES.

     The Company has periodically executed leasing arrangements in the United
Kingdom ("UK leases") relating to certain seismic and FPSO vessels and/or
equipment. Under the leases, generally, UK financial institutions ("Lessors")
acquired the assets from third parties and the Company leased the assets from
the Lessors under long-term charters that give the Company the option to
purchase the assets for a bargain purchase price at the end of the charter
periods. These UK leases provide the Lessors with the tax depreciation rights to
the assets and, therefore, the ability to utilize the related tax benefits.
Under these UK leases, the Company indemnified the Lessors against certain
future events that could reduce their expected after-tax returns. These events
include potential changes in UK tax laws and interpretations thereof (including
interpretations relating to depreciation rates) and changes in interest rates as
the leases are based on assumed interest rates.

     Due to the nature of the charters, the Company accounts for these leases as
capital leases. The Company legally defeased its future charter obligations for
the assets by making up-front, lump sum payments to unrelated large
institutional banks ("Payment Banks"), which then assumed the Company's
liability for making the periodic payments due under the long-term charters (the
"Defeased Rental Payments") equal to the basic rentals and termination sum
obligations, as defined in the agreements. The Company has no rights to the
amounts paid to Payment Banks. Due to the assumption of the charter
                                       F-9
<PAGE>

payment obligations by the Payment Banks, the Lessors legally released the
Company as the primary obligor under the charters. Accordingly, the Company
accounted for the release as a derecognition of the capital lease obligations
with respect to these UK leases.

     At the date that the Company executed any UK lease, the Company treated the
excess of the capitalized asset value over the amount required to legally
defease the charter obligations as a deferred gain. The deferred gain related to
indemnification for tax contingencies and for changes in future interest rates.
The portion of the deferred gain relating to changes in interest rates was
amortized over the term of the respective leases up to the date of adoption of
fresh start reporting. The portion of the deferred gain relating to tax
contingencies was recognized in income in accordance with Emerging Issues Task
Force ("EITF") Issue 89-20, "Accounting for Cross Border Tax Benefit Leases,"
when the Company determined that the likelihood of the indemnifications becoming
effective was remote. The Company amortized deferred gains associated with
interest rate changes of $1.0 million, $1.4 million and $0.9 million in the ten
months ending October 31, 2003 and years ending December 31, 2002 and 2001,
respectively, which is reported in other financial items, net. All deferred
gains relating to tax contingencies were recognized in the results of operations
prior to 2001.

     The Defeased Rental Payments are based on assumed Sterling LIBOR rates
between 8% and 9% (the "Assumed Interest Rates"). If actual interest rates are
greater than the Assumed Interest Rates, the Company receives rental rebates.
Conversely, if actual interest rates are less than the Assumed Interest Rates,
the Company is required to pay rentals in excess of the Defeased Rental Payments
(the "Additional Required Rental Payments"). During 2003, 2002, and 2001, actual
interest rates were below the Assumed Interest Rates, and the Company made
Additional Required Rental Payments of approximately $1.5 million, $3.9 million,
and $1.5 million, in the ten months ending October 31, 2003, and years ending
December 31, 2002 and 2001, respectively, which was expensed as incurred and
reported in other financial items, net.

     Effective November 1, 2003, the Company adopted fresh start reporting and
recorded a liability equal to the fair value of the future Additional Required
Rental Payments. Such fair value was estimated at the net present value of the
Additional Required Rental Payments based on forward market rates for Sterling
LIBOR and an 8% discount rate. This liability amounted to 30.5 million British
Pounds Sterling (approximately $51.6 million) at November 1, 2003, and was
amortized to $27.4 million British Pounds Sterling ($48.6 million) at December
31, 2003.

  RECEIVABLES CREDIT RISK.

     The Company's trade receivables are primarily from multinational integrated
oil companies and independent oil and natural gas companies, including companies
owned in whole or in part by foreign governments. The Company manages its
exposure to credit risk through ongoing credit evaluations of customers and has
provided for potential credit losses through an allowance for doubtful accounts.
The allowance for doubtful accounts reflects management's best estimate of
probable losses inherent in accounts receivable from trade customers and is
based on a number of factors consisting mainly of aging of accounts, historical
experience, customer concentration, customer creditworthiness, and current
industry and economic trends. The Company does not believe that exposure to
concentrations of credit risk is likely to have a material adverse impact on its
financial position or results of operations.

  MULTI-CLIENT LIBRARY.

     The multi-client library consists of seismic data surveys to be licensed to
customers on a nonexclusive basis. Costs directly incurred in acquiring,
processing and otherwise completing seismic surveys are capitalized into the
multi-client library, including the applicable portion of interest costs. Prior
to its adoption of fresh start reporting, the Company also capitalized certain
indirect costs and other associated costs that could be attributed to the
projects, including cost of relocating crews (steaming) between surveys and the
cost of yard stays. Subsequent to the adoption of fresh start reporting, PGS no
longer capitalizes such costs.

                                       F-10
<PAGE>

     The investment in the multi-client library is recorded in a manner
consistent with the capital investment and operating decision analysis, which
generally results in each component of the multi-client library being recorded
and evaluated separately. Projects that are in the same political regime, with
similar geological traits and that are marketed collectively are recorded and
evaluated as a group by year of completion (currently applies to certain surveys
in Brazil and the Gulf of Mexico).

     Amortization of the multi-client library is generally recorded in
proportion to revenue recognized to date as a percentage of the total expected
revenue. In determining the annual amortization rates applied to the
multi-client library, management considers expected future sales and market
developments as well as past experience. These expectations include
consideration of geographic location, prospects, political risk, exploration
license periods and general economic conditions. The local sales and operating
management estimate, at least annually, the total expected revenue for each
survey or group of surveys of the multi-client library. Because of the inherent
difficulty in estimating future sales and market developments, it is possible
that the amortization rates could deviate significantly from year to year. To
the extent that such revenue estimates, or the assumptions used to make those
estimates, prove to be higher than actual revenue, the Company's future
operations will reflect lower profitability due to increased amortization rates
applied to the multi-client library in later years, and the multi-client library
may also become subject to minimum amortization and/or impairment. Subsequent to
the adoption of fresh start reporting, for purposes of streamlining the
accounting method of amortization, the Company has categorized its multi-client
surveys into three amortization categories with amortization rates of 90%, 75%
or 60% of sales amounts. Classification of a project into a rate category is
based on the ratio of its remaining net book value to its remaining sales
estimate. Each category therefore includes surveys where remaining book value as
a percentage of remaining estimated sales is less than or equal to the
amortization rate applicable to each category.

     An integral component of amortization of the multi-client library is the
minimum amortization policy. Under this policy, the book value of each survey or
group of surveys of the multi-client library is reduced to a specified
percentage by year-end, based on the age of each survey or group of surveys in
relation to their year of completion. This requirement is applied each year-end
regardless of future revenue estimates for the multi-client library survey or
group of surveys. The specified percentage generates the maximum book value for
each multi-client library survey or group of surveys as the product of the
percentage multiplied by the original cost of the multi-client library survey or
group of surveys at the respective period end. Any additional or "minimum"
amortization charges required are then determined through a comparison of the
remaining book value to the maximum book value allowed for each survey or group
of surveys in the multi-client library.

     Subsequent to the adoption of fresh start reporting, the Company revised
the minimum amortization period from eight years for marine surveys and five
years for onshore surveys to five years for both marine and onshore projects
from the end of the year of completion (the year when the project is completed
and processed data is ready and available for use) and three years for
derivative processed projects (processing or reprocessing that creates data that
can be marketed and sold as an addition to the existing library) from the end of
the year of completion. With the adoption of fresh start reporting, existing
marine surveys were accorded a transition profile based on sales forecasts used
to compute their fair value.

                                       F-11
<PAGE>

     The specified percentages used to determine the maximum book value of
multi-client library components are summarized as follows:

<Table>
<Caption>
                                     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
-------------                    -------   -------   ------------------   ----------   ----------
<S>                              <C>       <C>       <C>                  <C>          <C>
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%
</Table>

  PROPERTY AND EQUIPMENT.

     Property and equipment are stated at cost less accumulated depreciation,
amortization and impairment charges. Depreciation and amortization are
calculated based on cost less estimated salvage values using the straight-line
method for all property and equipment, excluding leasehold improvements, which
are amortized over the asset life or lease term whichever is shorter.

     The estimated useful lives for property and equipment for the Predecessor
and Successor are as follows:

<Table>
<Caption>
                                                    SUCCESSOR COMPANY   PREDECESSOR COMPANY
                                                          YEARS                YEARS
                                                    -----------------   -------------------
<S>                                                 <C>                 <C>
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
</Table>

     Expenditures for major property and equipment that have an economic useful
life of at least one year are capitalized as individual assets and depreciated
over their useful lives. Maintenance and repairs, including periodic maintenance
and class surveys for FPSOs and seismic vessels, are expensed as incurred. The
Company capitalizes the applicable portion of interest costs to major capital
projects. When property and equipment are retired or otherwise disposed of, the
related cost and accumulated depreciation are removed from the accounts, and any
resulting gain or loss is included in the results of operations.

  OIL AND NATURAL GAS ASSETS.

     Following its adoption of fresh-start reporting, the Company uses the
successful efforts method of accounting for oil and natural gas properties.
Under this method, all costs of acquiring unproved oil and natural gas
properties and drilling and equipping exploratory wells are capitalized pending
determination of whether the properties have proved reserves. If an exploratory
well is determined to be non-productive, the drilling and equipment costs for
the well are expensed at that time. All development drilling and equipment costs
are capitalized. Capitalized costs of proved properties are amortized on a
property-by-property basis using the unit-of-production method whereby the ratio
of annual production to beginning of period proved oil and natural gas reserves
is applied to the remaining net book value of such properties. Oil and natural
gas reserve quantities represent estimates only and there are numerous
uncertainties inherent in the estimation process. Actual future production may
be materially different from amounts estimated, and such differences could
materially affect future amortization of proved properties. Geological and
geophysical costs are expensed as incurred.
                                       F-12
<PAGE>

     Long-lived assets to be held and used, including proved oil and natural gas
properties accounted for under the successful efforts method of accounting, are
assessed for impairment whenever events or circumstances indicate that the
carrying value of those assets may not be recoverable. An impairment loss is
indicated if the sum of the expected future cash flows, undiscounted, is less
than the carrying amount of the assets. In this circumstance, an impairment loss
is recognized for the amount by which the carrying amount of the asset exceeds
the estimated fair value of the asset.

     Unproved properties are periodically assessed for impairment and a loss is
recognized at the time of impairment. Unproved oil and natural gas properties
that are individually significant are periodically assessed for impairment by
comparing their cost to their estimated value on a project-by-project basis. The
remaining unproved oil and natural gas properties, if any, are aggregated and an
overall impairment allowance is provided based on historical experience.

     Prior to its adoption of fresh start reporting, the Company used the SEC
full cost 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 properties are capitalized. Such costs include lease
acquisition, geological, geophysical, drilling, equipment, interest and
overhead. Capitalized overhead costs are limited to salaries and benefits for
employees directly involved in the acquisition, exploration and development of
the properties as well 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 amortized using the
unit-of-production method on a country-by-country basis. Unevaluated properties
are excluded from the amortization base. Costs associated with unevaluated
properties are transferred into the amortization base at such time as the wells
are completed, the properties are sold, or the costs have been impaired. Future
development costs and dismantlement and abandonment costs are included in the
amortizable cost base.

     In accordance with the SEC guidelines for the full cost method, the cost
bases of proved oil and natural gas properties are limited, on a
country-by-country basis, to the estimated future net cash flows from proved oil
and natural gas reserves using prices and other economic conditions in effect at
the end of the reporting period, discounted at 10%, net of related taxes
(ceiling test). If the capitalized cost of proved oil and natural gas properties
exceeds this limit, the excess is charged to expense as additional depreciation
and amortization.

  GOODWILL.

     The Company adopted the provisions of Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS 142") as of
January 1, 2002. Under SFAS 142, goodwill and intangible assets acquired in a
purchase business combination and determined to have an indefinite useful life
are not amortized, but instead tested for impairment at least annually in
accordance with the provisions of SFAS 142. SFAS 142 also requires that
intangible assets with finite useful lives be amortized over their respective
estimated useful lives to their estimated residual values, and reviewed for
impairment in accordance with Statement of Financial Accounting Standards No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS
144").

     In connection with SFAS 142's transitional goodwill impairment evaluation,
the Company was required to perform an assessment of whether there was an
indication that goodwill was impaired as of the date of adoption. To accomplish
this, the Company identified its reporting units and determined the carrying
value of each reporting unit by assigning the assets and liabilities, including
the existing goodwill and intangible assets, to those reporting units as of
January 1, 2002, which included Marine Geophysical, Onshore, Production,
Atlantic Power (Production Services) and the reservoir consultant activities.
The Company was required to determine the fair value of each reporting unit and
compare it to the carrying amount of the reporting unit. To the extent the
carrying amount of a reporting unit exceeded the fair value of the reporting
unit, the Company would be required to perform the second step of the
transitional impairment test, which would require the Company to compare the
implied fair value of the reporting unit goodwill with the carrying amount of
the reporting unit goodwill. As of January 1, 2002, the second step
                                       F-13
<PAGE>

was required to be performed for the Company's Production and reservoir
consultants units as the implied fair value of the Company's reporting units
exceeded their respective carrying amounts. This resulted in a goodwill
impairment charge of $163.6 million upon adoption of SFAS 142 of which $161.1
million and $2.5 million related to the production and reservoir reporting units
respectively.

     In September 2002, the Company performed a similar test to that described
above, for its Marine Geophysical reporting unit due to identified impairment
factors, which included a significant reduction in the market value of the
Company. This resulted in a goodwill impairment charge of $9.4 million (see Note
5).

 INTANGIBLE ASSETS.

     Intangible assets other than goodwill generally relate to direct costs of
software product development, patents, royalties and licenses. In addition
several intangible assets were recognized as a consequence of the Company's
adoption of fresh start reporting. Such intangible assets include favorable
contracts, order backlog and the value of various existing technologies used in
the Company's operations. Intangible assets are stated at cost less accumulated
amortization and any impairment charges. Amortization is calculated on a
straight-line basis over estimated period of benefit, ranging from one to 10
years.

 OTHER LONG-LIVED ASSETS.

     Other long-lived assets consist of debt issue costs, long-term receivables,
and prepaid pension cost. Debt issue costs relating to long-term debt are
included in interest expense using the effective interest method over the period
the associated loans are outstanding.

 IMPAIRMENT OF LONG-LIVED ASSETS.

     Effective January 1, 2002, the Company adopted SFAS 144 which provides
guidance for evaluating the recoverability of all long-lived assets, principally
property, plant and equipment and definite-lived intangible assets. SFAS 144
provides similar guidance to Statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed of" ("SFAS 121"), which was applied prior to January 1,
2002. SFAS 144 requires that long-lived assets (or the group of assets,
including the asset in question, that represents the lowest level of separately
identifiable cash flows) be evaluated whenever events or changes in
circumstances indicate that the carrying amount of assets or cash generating
units may not be recoverable. The Company reviews long-lived assets or groups of
assets for impairment whenever events or changes in circumstances indicate that
the carrying amount may not be recoverable. If the total of the undiscounted
future cash flows is less than the carrying amount of the asset or group of
assets, an impairment loss is recognized for the difference between the
estimated fair value and the carrying value of the asset or groups of assets.
Long-lived assets (multi-client library, property and equipment and oil and
natural gas assets accounted for under the successful efforts method) are
assessed for possible impairment upon the occurrence of a triggering event.
Events that can trigger assessments for possible impairments include, but are
not limited to (i) significant decreases in the market value of an asset, (ii)
significant changes in the extent or manner of use of an asset, (iii) a physical
change in the asset, (iv) a reduction of proved oil and natural gas reserves
based on field performance and (v) a significant decrease in the price of oil or
natural gas. Prior to the adoption of fresh-start reporting, oil and natural gas
assets were assessed for impairment in accordance with the full cost accounting
guidelines as described under "Oil and Natural Gas Assets" above.

 STEAMING AND MOBILIZATION.

     Subsequent to the adoption of fresh start reporting, costs incurred while
moving or "steaming" a vessel or crew from one location to another are expensed
as incurred. Onsite project costs such as positioning, deploying and retrieval
of equipment at the beginning and end of a project are considered mobilization
or demobilization costs and are included in the cost of the multi-client survey
or exclusive contract with which the costs are associated. Prior to fresh start,
the Company (Predecessor) capitalized a

                                       F-14
<PAGE>

proportionate share of cost incurred while moving or "steaming" a seismic vessel
or crew as part of the cost of multi-client surveys.

  DERIVATIVE FINANCIAL INSTRUMENTS.

     On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards 133, "Accounting for Derivative Instruments and Hedging Activities, as
amended" ("SFAS 133"). Under SFAS 133, all derivative instruments are recognized
in the balance sheet at their fair values while realized and unrealized gains
and losses attributable to derivative instruments that do not qualify for hedge
accounting are recognized in income as they arise. To qualify for hedge
accounting, the details of the hedging relationship must be formally documented
at inception of the arrangement, including the risk management objective,
hedging strategy, hedged items, specific risks that are being hedged, the
derivative instrument and how effectiveness is being assessed. There are three
types of hedges: cash flow hedges, which are hedges that use derivatives to
offset the variability of expected future cash flow, fair value hedges, which
are hedges that eliminate the risk of changes in the fair value of assets,
liabilities and certain firm commitments, and net investment hedges, which hedge
foreign currency exposure of a net investment in a foreign operation. The
adoption of SFAS 133 did not have any material impact on the Company's financial
position or results of operations.

     The Company uses derivative financial instruments periodically to manage
exposure to changes in foreign currency exchange rates, changes in interest
rates on variable rate debt, and firm commitments or expected future cash flows
associated with the purchases of property, plant and equipment. The Company may
also use derivatives to manage exposure to commodity price fluctuations for oil
and natural gas. The Company does not engage in derivative financial instrument
transactions for speculative purposes. As of December 31, 2003 and 2002, the
Company did not have outstanding any derivative financial instruments that
qualified for hedge accounting.

     During 1998 and 1999, the Company entered into forward foreign currency
exchange contracts known as tax equalization swaps ("TES") related to its senior
unsecured notes, its Oslo Seismic mortgage notes and its trust preferred
securities. These contracts hedge the risk related to the cash tax effect of
unrealized exchange rate fluctuations between the Norwegian Kroner and the US
dollar related to the Company's US dollar-denominated debt and trust preferred
securities, where such foreign currency exchange gains and losses are taxable
and deductible for Norwegian statutory tax purposes. In 2002, all outstanding
TES contracts were terminated and the Company received $21.0 million from the
counter-party as the termination settlement, which resulted in a gain of $45.3
million. The changes in fair value (including accruals for cash payments and
realized and unrealized gains and losses) of the TES for the years ending
December 31, 2002 and 2001 were $45.3 million and ($9.1) million, respectively,
exclusive of any tax effects and are recorded in other financial items, net.

  SHARE BASED COMPENSATION PLANS.

     The Company applies the intrinsic value method in accordance with
Accounting Principles Board ("APB") Opinion 25, "Accounting for Stock Issued to
Employees," in accounting for its share-based compensation plans and has adopted
the disclosure-only provisions of Statement of Financial Accounting Standards
No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), as amended by
SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure". Accordingly, no compensation cost is recognized under these plans
since the option exercise price is above or equal to market value of the stock
at measurement date. The Company discloses the amount the compensation cost
would have been had the share-based compensation been determined and recognized
based on fair values of options awarded.

     If the compensation cost for the share-based compensation plans had been
determined based on the fair values of the options awarded at the grant dates,
consistent with the provisions of SFAS 123, the net

                                       F-15
<PAGE>

income (loss) and earnings (loss) per share would have been affected on a pro
forma basis as indicated below:

<Table>
<Caption>
                                        SUCCESSOR
                                         COMPANY               PREDECESSOR COMPANY
                                       ------------   --------------------------------------
                                        TWO MONTHS    TEN MONTHS
                                          ENDED          ENDED       YEARS ENDED DECEMBER,
                                       DECEMBER 31,   OCTOBER 31,   ------------------------
                                           2003          2003          2002          2001
                                       ------------   -----------   -----------   ----------
                                                     (IN THOUSANDS OF DOLLARS)    (RESTATED)
<S>                                    <C>            <C>           <C>           <C>
Net income (loss), as reported.......    $(9,953)      $557,045     $(1,174,678)  $(172,479)
Deduct: Total share-based
  compensation expense determined
  under the fair value based method
  for all awards, net of related tax
  effect.............................         --         (5,105)         (9,804)    (10,630)
                                         -------       --------     -----------   ---------
  Pro forma, net income (loss).......    $(9,953)      $551,940     $(1,184,482)  $(183,109)
                                         =======       ========     ===========   =========
Net income (loss) per share:
  Basic and diluted -- as reported...    $ (0.50)      $   5.39     $    (11.37)  $   (1.68)
  Basic and diluted -- pro forma.....    $ (0.50)      $   5.34     $    (11.46)  $   (1.78)
</Table>

     The Company did not grant any share option awards during 2003 or 2002. For
share options awards granted during 2001, the fair value of each option award on
the grant date was estimated using the Black-Scholes option-pricing model with
the following weighted average assumptions: expected volatility of 55%;
risk-free interest rate of 4.23%; and expected life of 3.4 years. Dividend yield
was assumed to be zero.

  REVENUE RECOGNITION.

     The Company recognizes revenue when persuasive evidence of a sale
arrangement exists, delivery has occurred or services have been rendered, the
sales price is fixed or determinable and collectibility is reasonably assured.
The Company defers the unearned component of payments received from customers
for which the revenue recognition requirements have not been met. On July 1,
2003, the Company adopted the provisions of EITF 00-21, "Revenue Arrangement
with Multiple Deliverables". Consideration is allocated among the separate units
of accounting based on their relative fair values. The adoption of EITF 00-21
did not have a material impact on the Company's financial position or results of
operations for the ten-month period ended October 31, 2003 or the two-month
period ended December 31, 2003. The Company's revenue recognition policy is
described in more detail below.

     1.  GEOPHYSICAL SERVICES (MARINE AND ONSHORE)

     (a) SALES OF MULTI-CLIENT LIBRARY DATA.

     Late sales -- The Company grants a license to a customer, which entitles
the customer to have access to a specifically defined portion of the
multi-client data library. The customer's license payment is fixed and
determinable and typically is required at the time that the license is granted.
The Company recognizes revenue for late sales when the customer executes a valid
license agreement and has been granted access to the licensed portion of the
multi-client library and collection is reasonably assured.

     Volume sales agreements -- The Company grants licenses to customers for
access to a specified number of blocks of multi-client library within a defined
geographical area. These licenses typically enable the customer to select and
access the specific blocks over a period of time. Although the license fee is
fixed and determinable in all cases, the payment terms of individual volume
sales agreements vary, ranging from payment of the entire fee at the
commencement of the volume sales agreement, to installment payments over a
multi-year period, to payment of the license fee as the specific blocks are
selected.

     Revenue recognition for volume sales agreements is based on a ratable
portion of the total volume sales agreement revenue, measured as the customer
executes a license for specific blocks and has been granted access to the data
and collection is reasonably assured.

                                       F-16
<PAGE>

     Pre-funding arrangements -- The Company obtains 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.

     Pre-funding revenue is recognized as the services are performed on a
proportional performance basis. Progress is measured in a manner generally
consistent with the physical progress on the project, and revenue is recognized
based on the ratio of the project's progress to date to the total project
revenues, provided that all other revenue recognition criteria are satisfied.

     (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 that customer. The Company
recognizes proprietary/contract revenue as the services are performed and become
chargeable to the customer on a proportionate performance basis over the term of
each contract. Progress is measured in a manner generally consistent with the
physical progress of the project, and revenue is recognized based on the ratio
of the project's progress to date to the total project revenues, provided that
all other revenue recognition criteria are satisfied.

     (c) OTHER GEOPHYSICAL SERVICES.

     Revenue from other geophysical services is recognized as the services are
performed, provided all other recognition criteria are satisfied.

     2.  PRODUCTION

     Tariff-based revenue from Production services is recognized as production
occurs, while day-rate revenue is recognized over the passage of time, provided
all other recognition criteria are satisfied.

     3.  PERTRA

     Revenue from production and sale of oil produced under production licenses
is recognized as produced barrels are lifted and ownership passes to the
customer, provided all other recognition criteria are satisfied.

     Capitalization of costs associated with a revenue contract is limited to
the deferred revenue related to the contract. In the Consolidated Statements of
Operations reimbursements received for expenses incurred under a contract are
characterized as revenue in line with EITF 01-14 "Income Statement
Characterization of Reimbursements Received for 'Out-of-Pocket' Expenses
Incurred".

  INCOME TAXES.

     Deferred tax assets and liabilities are recognized for the expected future
tax consequences of transactions and events. Under this method, deferred tax
assets and liabilities are determined based on the difference between the
financial statement and tax bases of assets and liabilities using enacted tax
rates in effect for the year in which the differences are expected to reverse.
Deferred tax assets are reduced by a valuation allowance to record the deferred
tax assets at an amount expected to be more likely than not recoverable.
Deferred tax assets and liabilities are adjusted for the effects of changes in
tax laws and rates on the date of enactment. In accordance with Accounting
Principles Board Opinion No. 23, "Accounting for Income Taxes -- Special Areas,"
the Company does not recognize any deferred tax liability on unremitted earnings
of foreign subsidiaries when remittance is indefinite.

  ASSET RETIREMENT OBLIGATIONS.

     On January 1, 2003, the Company adopted Statement of Financial Accounting
Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143").
SFAS 143 requires entities to record the fair value of an asset retirement
obligation ("ARO") as a liability in the period when it is incurred

                                       F-17
<PAGE>

(typically when the asset is installed at the production location). When the
liability is recorded, the entity capitalizes the cost by increasing the
carrying amount of the related properties, plant and equipment. Over time, the
liability is increased for the change in its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset. Also,
revisions to a previously recorded ARO may result from changes in the
assumptions used to estimate the cash flows required to settle the ARO.

     The Company has asset retirement obligations associated with its oil and
gas producing activities in the Norwegian North Sea and with the sub-sea
production facility associated with its Ramform Banff FPSO also operating in the
North Sea. These obligations generally relate to restoration of the environment
surrounding the facility and removal and disposal of all the production
equipment. For oil and natural gas production facilities, the obligations are
generally statutory as well as contractual. The asset retirement obligations
will be reduced by grants from the Norwegian government, and with contractual
payments from FPSO contract counterparts. These receivables have been included
in the balance sheet under long-term receivables.

     If the accounting change we implemented during 2003 for asset retirement
obligations had been effective in 2002 and 2001, the impact on income before
cumulative effect of changes in accounting principles and earnings per share
would have been immaterial for all periods presented. Computed on a pro forma
basis as if SFAS 143 had been applied during all periods presented, the asset
retirement obligation would have been $59.0 million and $20.7 million as of
January 1, 2003, and January 1, 2002, respectively.

     Upon adoption of SFAS 143 on January 1, 2003, the Company recorded $2.4
million (net of taxes) as income from cumulative effect of changes in accounting
principles. Application of this new accounting principle resulted in an increase
in property, plant and equipment of $6.5 million, an increase in the recorded
asset retirement obligation liability of $1.5 million, and a decrease in the
recorded long-term receivables of $2.6 million.

     The following table presents the movements in ARO for the ten months ending
October 31, 2003, and the two months ending December 31, 2003:

<Table>
<Caption>
                                                            SUCCESSOR         PREDECESSOR
                                                             COMPANY            COMPANY
                                                        -----------------   ----------------
                                                           TWO MONTHS          TEN MONTHS
                                                              ENDED              ENDED
ASSET RETIREMENT OBLIGATION                             DECEMBER 31, 2003   OCTOBER 31, 2003
---------------------------                             -----------------   ----------------
                                                             (IN THOUSANDS OF DOLLARS)
<S>                                                     <C>                 <C>
Balance at beginning of period........................       $49,847            $59,767
Accretion expense.....................................           599              3,793
Liabilities settled in the period.....................          (430)                --
Revision in estimated cash flow/fair value............            --            (13,713)
                                                             -------            -------
Balance at end of period..............................       $50,016            $49,847
                                                             =======            =======
</Table>

Governmental grants and contractual receivables related to the asset retirement
obligation are included in other long-lived assets with $16.8 million at
December 31, 2003 and $17.2 million at December 31, 2002.

  VARIABLE INTEREST ENTITIES.

     In January 2003, the Financial Accounting Standards Board ("FASB") issued
FASB Interpretation No. 46 ("FIN 46") "Consolidation of Variable Interest
Entities," and in December 2003, the FASB issued a revised FIN 46 ("FIN 46R"),
which addresses when a company should include in its financial statements the
assets, liabilities and activities of another entity. FIN 46R requires
consolidation of a variable interest entity ("VIE") if the reporting entity is
subject to a majority of the risk of loss from the VIE's activities or is
entitled to receive a majority of the VIE's residual returns or both. The
consolidation requirements of FIN 46R apply immediately to VIEs created after
January 31, 2003, and to all other existing structures commonly referred to as
special purpose entities. The consolidation requirements applied to VIEs created
prior to January 31, 2003 and apply to the Company upon the adoption of fresh-
start reporting.

                                       F-18
<PAGE>

     The Company has concluded that it is the primary beneficiary of two VIEs,
DMNG PGS AS and Walter Herwig AS. Accordingly, these entities are consolidated
in the Successor's financial statements. By December 31, 2003 Walter Herwig AS
was a 100% owned subsidiary of the Company. The operations, assets and
liabilities of DMNG PGS AS are not material to the Company's financial
statements.

     In addition, the Company has considered its UK leases in relation to FIN
46R. Based on the characteristics of the lessor entities, the Company has
determined that the entities are likely to be VIEs. As part of the evaluation
process, the Company has requested further information about the lessor
entities, including information related to their other assets and contractual
arrangements. However, the Company has no rights under its agreements with the
lessor entities to request or receive such information, and the lessor entities
(or their owners) have denied the Company access to any such information.
Accordingly, the Company has not been able to affirmatively determine if any of
the lessor entities are in fact VIEs, and if any are VIEs, who the primary
beneficiary would be.

     However, based on information received from the lessor entities, which are
all multi-lessee entities, the debt issued to finance the activities of the
entities is full recourse to all assets of each entity. Based on publicly
available information and confirmations from the lessor entities, the Company
has determined that its relative portions of the fair value of the assets of the
lessor entities are less than 50% of the assets of each entity. Accordingly, the
Company has determined that it is not the primary beneficiary of these lessor
entities and that the UK leases are not separate silos within the lessor
entities (separate VIEs).

     The Company has certain contingent obligations under its UK leases the
maximum amount of which is not determinable. See note 19 for further discussion
of these contingent liabilities.

  COMMITMENTS AND CONTINGENCIES.

     The Company accrues for loss contingencies when it is probable that a loss
will result from a contingency, and the amount of the loss can be reasonably
estimated. In connection with the adoption of fresh start reporting,
contingencies were recorded at their estimated fair values even if they were not
considered probable.

  PRO FORMA INFORMATION.

     As described above the Company adopted the provisions of SFAS 142,
effective January 1, 2002 and SFAS 143, effective January 1, 2003. The pro forma
effects of these changes in accounting for preceding years are shown in the
table below:

<Table>
<Caption>
                                     LOSS FROM CONTINUING
                                 OPERATIONS BEFORE CUMULATIVE         INCOME (LOSS) BEFORE
                                      EFFECT OF CHANGE IN        CUMULATIVE EFFECT OF CHANGE IN
                                     ACCOUNTING PRINCIPLES            ACCOUNTING PRINCIPLE            NET INCOME (LOSS)
                                 -----------------------------   -------------------------------   ------------------------
                                     2002            2001             2002             2001           2002          2001
                                 -------------   -------------   ---------------   -------------   -----------   ----------
                                                  (RESTATED)                        (RESTATED)                   (RESTATED)
                                                      (IN THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
<S>                              <C>             <C>             <C>               <C>             <C>           <C>
Reported income (loss).........    $(809,903)      $(140,125)      $(1,011,040)      $(172,479)    $(1,174,678)  $(172,479)
Add back goodwill
  amortization.................           --           5,162                --           6,390              --       6,390
Asset removal obligation pro
  forma effect.................          362             792               362             792             362         792
Reverse cumulative effect of
  change in accounting
  principle....................           --              --                --              --         163,638          --
                                   ---------       ---------       -----------       ---------     -----------   ---------
Pro forma income (loss)........    $(809,541)      $(134,171)      $(1,010,678)      $(165,297)    $(1,010,678)  $(165,297)
                                   =========       =========       ===========       =========     ===========   =========
Pro forma income (loss) per
  share (basic and diluted)....    $   (7.83)      $   (1.31)      $     (9.78)      $   (1.61)    $     (9.78)  $   (1.61)
</Table>

                                       F-19
<PAGE>

NOTE 3 -- FINANCIAL RESTRUCTURING AND FRESH START REPORTING

 BACKGROUND OF RESTRUCTURING.

     The Company had approximately $1.1 billion of debt and other contractual
obligations maturing during 2003, of which $930 million were bank and senior
note obligations of PGS ASA. Based on the Company's existing business plan and
forecast at that time, it became clear that the Company was over leveraged and
that a comprehensive financial restructuring was crucial to the long-term
viability of the Company. In early 2003, the Company was also in violation of
certain financial and other covenants of various bank credit and leasing
agreements, and as such, had been seeking waivers of these defaults. These
circumstances were largely the result of over investing in marine geophysical
capacity, as well as excess investments in the late 1990's, financed with
substantial amounts of debt, in the Ramform Banff FPSO, Atlantis (an oil and
natural gas subsidiary) and the multi-client data library, and subsequent
underperformance by these assets. As a result, on July 29, 2003, the Company
filed a voluntary petition for protection under Chapter 11 of the United States
Bankruptcy Code. The filing was based on a financial restructuring plan that was
pre-approved by a majority of banks and bondholders and a group of the Company's
largest shareholders. The Company emerged from Chapter 11 on November 5, 2003.

 FINANCIAL RESTRUCTURING.

     In accordance with the plan of reorganization, $2,140 million of the
Company's senior unsecured debt was canceled and the associated creditors
received the following:

     - $746 million of 10% senior unsecured notes due 2010;

     - $250 million of 8% senior unsecured 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 in cash distributed by PGS, 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 outstanding immediately
prior to the effectiveness of the restructuring, consisting of 103,345,987
shares, par value NOK 5 per share, 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 (one new share
per 129 old shares), and the right to acquire 30%, or 6,000,000, of the new
ordinary shares (1,500,000 of which were committed to shareholders underwriting
the rights offering and 4,500,000 of which were available to all
pre-restructuring shareholders 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 securities received 5%, or
1,000,000, of the new ordinary shares. The principal amount of the Company's
interest bearing debt and capital lease obligations immediately after the
restructuring was approximately $1,210 million, a reduction of approximately
$1,283 million.

  REORGANIZATION VALUE.

     The Company adopted fresh start reporting upon its emergence from Chapter
11 in accordance with SOP 90-7. Accordingly, all assets and liabilities were
adjusted to reflect their reorganization value as of November 1, 2003, which
approximates fair value at the date of reorganization. The Company engaged
independent financial advisors to assist in the determination of its
reorganization value as defined in SOP 90-7. In the disclosure statement dated
September 10, 2003 prepared in the bankruptcy proceeding,

                                       F-20
<PAGE>

the Company, together with financial advisors, determined a reorganization value
as an enterprise value in the range of $1.3 and $1.7 billion. On this basis the
Company determined that the reorganization value for the Company as defined by
SOP 90-7 should be close to the mid-range of $1.5 billion.

     This value was determined using various valuation methods including: (i)
publicly traded company analysis; (ii) discounted cash flow analysis; and (iii)
precedent transactions analysis as follows:

          (i) Market values and trading multiples of selected publicly held
     companies in comparable lines of business were analyzed (FPSO and
     Geophysical businesses). The enterprise values of the selected companies
     were calculated as a multiple of certain historical and projected financial
     data of such companies. These multiples were compared with multiples
     derived by assigning a range of enterprise values for the corresponding
     projected financial data of the applicable business of the reorganized PGS.

          (ii) A discounted cash flow analysis was performed for each of the
     business segments, incorporating assumptions for the allocation of
     corporate and other costs to each business, to estimate the present value
     of each business' future unlevered, after-tax cash flows based on the
     financial projections. This was calculated as the sum of the present value
     of its cash flows through 2010 and the present value of its terminal value
     as of 2010.

               In addition, a discounted cash flow analysis on each of the main
     assets was performed to estimate the present value of future unlevered,
     after-tax cash flows for each of the primary assets based on financial
     projections extending until the end of the useful life of each of the
     primary assets, ascribing no further residual or terminal value. The
     negative present value of corporate and other costs was separately valued
     with a similar approach. A range of discount rates was used to arrive at a
     range of present values for each asset. These present values were
     aggregated to arrive at a range of sum of the parts present value.

          (iii) Selected recently completed or announced transactions at the
     time of reorganization with relevance to the Company were reviewed.
     Enterprise values were calculated using the transactions as multiples of
     certain historical financial data of such companies. These multiples were
     compared to multiples derived by assigning a range of enterprise values to
     the applicable business segment of the Company and dividing those
     enterprise values by the corresponding historical financial data of the
     applicable segment of the Company.

     These analyses are necessarily based on a variety of estimates and
assumptions which, though considered reasonable by management, may not be
realized and are inherently subject to significant business, economic and
competitive uncertainties and contingencies, many of which are beyond the
Company's control. These estimates and assumptions had a significant effect on
the determination of the reorganization value. The assumptions used in the
calculations for the discounted cash flow analysis were provided by management
based on their best estimate at the time the analysis was performed. These
estimates and assumptions are subject to uncertainties and contingencies beyond
the Company's control. Accordingly, there can be no assurance that the
estimates, assumptions and values reflected in the valuations will be realized,
and actual results could vary materially.

  FRESH START REPORTING.

     The consolidated balance sheet as of December 31, 2003 and the statements
of operations and cash flow for the two months ended December 31, 2003 are for
the Successor and give effect to adjustments to the carrying value of assets or
amounts and classifications of liabilities that were necessary upon adoption of
fresh start reporting as of November 1, 2003. The statements of operations and
cash flows for the years ended December 31, 2001 and 2002 and for the ten months
ended October 31, 2003, and the consolidated balance sheet as of December 31,
2002 are for the Predecessor and reflect the assets and liabilities of PGS on a
historical cost basis including the effect at October 31, 2003 of the fresh
start adjustments. The adoption of fresh start reporting had a material effect
on the consolidated balance sheet as of December 31, 2003 and for the two-month
period then ended and will have a material impact on

                                       F-21
<PAGE>

consolidated statements of operations for periods subsequent to December 31,
2003. Consequently, the financial information for the Successor and Predecessor
companies is not comparable.

     In connection with the adoption of fresh start reporting on November 1,
2003, the Company also adopted new accounting policies for certain transactions
and activities related to the multi-client library, steaming and mobilization
costs, certain other property and equipment, and oil and natural gas
exploration, development and production activities. All new accounting policies
under fresh start are described in Note 2.

     The following table summarizes the adjustments required to record the
reorganization and the issuance of the various securities in connection with the
implementation of the plan:
<Table>
<Caption>
                                                                      RECOVERY
                                                      -----------------------------------------
PGS ASA PLAN OF                         ELIMINATION
REORGANIZATION            PREDECESSOR   OF DEBT AND   SURVIVING               2010       2006
RECOVERY ANALYSIS           COMPANY       EQUITY        DEBT       CASH       NOTE       NOTE
-----------------         -----------   -----------   ---------   -------   --------   --------
                                      (IN THOUSANDS OF DOLLARS, EXCEPT PERCENTAGES)
<S>                       <C>           <C>           <C>         <C>       <C>        <C>
Other liabilities -- not
 affected...............  $  338,536    $        --   $     --    $    --   $     --   $     --
                          ----------
Unsecured Debt..........   2,140,000     (2,140,000)        --     40,592    745,949    250,000
Trust Preferred
 Securities (incl.
 accrued interest)......     155,203       (155,203)        --         --         --         --
Capital lease
 obligations............      89,913             --     89,913         --         --         --
Senior Secured Debt.....     113,970             --    113,970         --         --         --
Debt of
 Subsidiaries -- not
 affected...............       5,295             --      5,295         --         --         --
Common Stockholders.....      71,089        (71,089)        --         --         --         --
Deficit.................    (429,531)       429,531         --         --         --         --
                          ----------    -----------   --------    -------   --------   --------
Total...................  $2,484,475    $(1,936,761)  $209,178    $40,592   $745,949   $250,000
                          ==========    ===========   ========    =======   ========   ========
Adjusted for fair value
 adjustment of interest
 rate variation on UK
 leases.................
Adjusted for cash.......
Reorganization value....

<Caption>
                                              RECOVERY
                          -------------------------------------------------
PGS ASA PLAN OF                         COMMON STOCK       TOTAL RECOVERY
REORGANIZATION            TERM LOAN   -----------------   -----------------
RECOVERY ANALYSIS         FACILITY      %       VALUE      %       VALUE
-----------------         ---------   ------   --------   ----   ----------
                            (IN THOUSANDS OF DOLLARS, EXCEPT PERCENTAGES)
<S>                       <C>         <C>      <C>        <C>    <C>
Other liabilities -- not
 affected...............   $   --              $     --          $       --
Unsecured Debt..........    4,810      91.0%    330,458    64%    1,371,809
Trust Preferred
 Securities (incl.
 accrued interest)......       --       5.0%     18,157    12%       18,157
Capital lease
 obligations............       --         --         --   100%       89,913
Senior Secured Debt.....       --         --         --   100%      113,970
Debt of
 Subsidiaries -- not
 affected...............       --         --         --   100%        5,295
Common Stockholders.....       --       4.0%     14,526    20%       14,526
Deficit.................       --         --         --                  --
                           ------     ------   --------   ----   ----------
Total...................   $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
                                                                 ==========
</Table>

     Fresh start adjustments reflect the allocation of fair value to current and
long-lived assets and the present value of liabilities to be paid as calculated
with the assistance of independent third party valuation specialists. Current
and long-lived assets were valued based on a combination of the cost, income and
market approach. Also considered were technical, functional and economic
obsolescence.

     In applying fresh start reporting, the Company followed these principles:

     - 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 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 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 20). Valuation allowances have been provided for deferred tax
       assets.

                                       F-22
<PAGE>

     - 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.

     The following table summarizes the reconciliation of the Predecessor
Company's consolidated balance sheet, as of October 31, 2003, to that of the
Successor Company's opening balance sheet as of November 1, 2003, giving effect
to the emergence from Chapter 11 reorganization and the adoption of fresh-start
reporting:

<Table>
<Caption>
                                              OCTOBER 31,
                                                 2003                    NOVEMBER 1, 2003
                                              -----------   ------------------------------------------
                                              PREDECESSOR                     FRESH START   SUCCESSOR
                                                COMPANY     EFFECTS OF PLAN    VALUATION     COMPANY
                                              -----------   ---------------   -----------   ----------
                                                             (IN THOUSANDS OF DOLLARS)
<S>                                           <C>           <C>               <C>           <C>
                                                ASSETS
Cash and cash equivalents...................  $   93,951      $        --      $      --    $   93,951
Restricted cash.............................      44,947               --             --        44,947
Accountants receivable, net.................     162,288               --          2,000       164,288
Unbilled and other receivables..............      30,771               --             --        30,771
Other current assets........................      57,625               --         (2,405)       55,220
Assets of discontinued operations...........       2,753               --             --         2,753
                                              ----------      -----------      ---------    ----------
          Total current assets..............     392,335                            (405)      391,930
Multi-client library, net...................     437,732               --         (7,151)      430,581
Property and equipment, net.................   1,577,065               --       (507,968)    1,069,097
Oil and natural gas assets, net.............      23,345               --            574        23,919
Restricted cash.............................      10,014               --             --        10,014
Investments in associated companies.........       9,246               --           (205)        9,041
Intangible assets, net......................       3,636               --         52,383        56,019
Other long-lived assets.....................      31,102               --          7,601        38,703
                                              ----------      -----------      ---------    ----------
          Total assets......................  $2,484,475      $        --      $(455,171)   $2,029,304
                                              ==========      ===========      =========    ==========

                                 LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt and current portion of
  long-term debt............................  $2,294,995      $(2,283,395)     $      --    $   11,600
Current portion of capital lease
  obligations...............................      19,561               --             --        19,561
Debt and other liabilities of discontinued
  operations................................       1,252               --             --         1,252
Accounts payable............................      36,927               --             --        36,927
Accrued expenses............................     152,228           29,139         (4,818)      176,549
Income taxes payable........................      22,570               --             --        22,570
                                              ----------      -----------      ---------    ----------
          Total current liabilities.........   2,527,533       (2,254,256)        (4,818)      268,459
Long-term debt..............................     108,015        1,000,405             --     1,108,420
Capital lease obligations...................      70,352               --             --        70,352
Other long-term liabilities.................     115,095               --         83,732       198,827
Deferred tax liabilities....................      21,095               --         (1,817)       19,278
                                              ----------      -----------      ---------    ----------
          Total liabilities.................   2,842,090       (1,253,851)        77,097     1,665,336
                                              ----------      -----------      ---------    ----------
Minority interest in consolidated
  subsidiaries..............................         827               --             --           827
Shareholders' equity:
  Common stock..............................      71,089           14,625             --        85,714
  Additional paid-in capital................          --          809,695       (532,268)      277,427
  Retained earnings (deficit)...............    (397,520)         397,520             --            --
  Accumulated other comprehensive income
     (loss).................................     (32,011)          32,011             --            --
                                              ----------      -----------      ---------    ----------
          Total shareholders' equity
            (deficit).......................    (358,442)       1,253,851       (532,268)      363,141
                                              ----------      -----------      ---------    ----------
          Total liabilities and
            shareholders' equity............  $2,484,475      $        --      $(455,171)   $2,029,304
                                              ==========      ===========      =========    ==========
</Table>

                                       F-23
<PAGE>

NOTE 4 -- RESTATEMENT OF 2001 FINANCIAL STATEMENTS

     In preparing the 2003 and 2002 financial statements and in the course of
the re-audit of the 2001 financial statements, accounting errors were identified
that related to previously filed financial statements. As a result, the Company
has restated its consolidated balance sheet as of December 31, 2001, and
consolidated statements of operations, cash flows and changes in shareholders'
equity for the year ended December 31, 2001. The restatements also affected
periods prior to 2001. The impact of the restatement on such prior periods was
reflected as an adjustment to retained earnings as of January 1, 2001. The
restatements (i) correct certain of the Company's historical accounting policies
to conform to US GAAP and (ii) correct certain errors made in the application of
US GAAP; both of which are "errors" within the meaning of APB Opinion No. 20,
"Accounting Changes." Set forth below are the restatement adjustments for the
year ended December 31, 2001.

  REVENUE RECOGNITION.

     The Company's revenue recognition policy is based on the guidelines in
Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial
Statements," as described in Note 2, which was in effect for the Company's
financial statements for years ended December 31, 2000 and later years. However,
certain errors were identified in the application of the accounting policy
relating to revenue recognition. These errors primarily related to the
recognition of revenue prior to: a) obtaining persuasive evidence of an
arrangement as certain amounts were recorded as revenue prior to receiving
signatures on final agreements or obtaining written agreements, and/or b)
obtaining sales prices that were fixed or determinable as the agreed upon price
was not final. Restatement entries were made to reverse the recognized revenue
and related cost of sales on these transactions. In addition, revenues in 2001
were restated to recognize revenues from previous years that had been recognized
prematurely and restated in the 2001 opening balance.

  ACCOUNTING FOR MULTI-CLIENT LIBRARY.

     The Company incurs acquisition costs in the course of self-constructing its
multi client library assets which are capitalized pursuant to US GAAP. Errors
were determined to have occurred in capitalizing certain general and
administrative costs, sales commissions, project management costs, data
management costs and technology costs. The Company did not maintain consistent
adequate detailed documentation to distinguish between the costs incurred
associated with the creation of the asset and the costs associated with selling
and administrative efforts. The restatements to the multi-client library
acquisition cost also affected capitalized interest, amortization expense and
impairments as a consequence of adjusted acquisition cost. Impairments in
periods prior to 2001 were recorded based on undiscounted cash flows. This has
been restated in the opening retained earnings balance.

  ACCOUNTING FOR FPSOS.

     The Company re-evaluated costs that were capitalized in connection with
upgrade and repair projects on the Ramform Banff and Petrojarl I FPSO vessels
that were completed during 2000 and 2001. As a result, expenditures were
identified that should have been included as operating costs as they did not
increase the useful life or capacity of the vessels. The effects of these
restatements were adjustments to retained earnings in the opening balance, the
carrying value of each vessel and related operating and depreciation expenses.

     The Company re-evaluated an impairment charge of the subsea assets related
to the Banff field reflected in retained earnings at January 1, 2001. The
Company determined that the impairment charge resulted from an improper
application of US GAAP as cash flows are not separately identifiable. As a
result, the impairment charge of $31.6 million was reversed; thereby, increasing
retained earnings and the carrying value of property and equipment at January 1,
2001.

     Certain of the Company's FPSOs were depreciated using a
"modified-units-of-production" method. The Company determined that the
straight-line method should have been used from the time the assets
                                       F-24
<PAGE>

were placed in service. As a result, the cumulative effect of this restatement
was adjusted to the opening retained earnings balance and depreciation expense
for the year ended December 31, 2001 was restated.

     The Company depreciates its FPSOs based on cost less salvage value. An
error was identified in the amounts of salvage values historically used by the
Company for all four FPSOs as it was determined such salvage values were
overstated at January 1, 2001. As a result, the salvage values were reduced
prospectively from January 1, 2001, and depreciation expense for the year ended
December 31, 2001 was restated.

  ASSET RETIREMENT OBLIGATION FOR BANFF FIELD.

     The Company determined that an asset retirement obligation and a related
contractual receivable due from the operator should have been recognized
separately in the balance sheet at inception of the contract in January 1999.
Originally, the Company recorded none of these. The effect of this restatement
is that the value of the receivable will be recognized as other long-lived
assets and the asset retirement obligation in other long-term liabilities
accreted based on production over the lifetime of the field, which started in
January 1999. The accumulated effect is restated in the 2001 opening retained
earnings balance, while the build-up of the liability for the year ended
December 31, 2001 is charged to net income.

  CONTRACT LOSS ACCRUALS.

     The Company determined that contract loss accruals for service contracts
recorded prior to 2001, and partly released into earnings in the year ending
December 31, 2001, did not have support under US GAAP, except when SOP 81-1,
"Accounting for Performance of Construction Type and Certain Production Type
Contracts" is used, or the Company has committed to exit the contracts. The
effect of this restatement was an adjustment to the opening retained earnings
balance and the balance sheet for the year ended December 31, 2001, and a
reduction in net income for the year ended December 31, 2001.

  LEASE ACCOUNTING.

     The Company identified errors associated with four leases that were
originally accounted for as operating leases prior to 2001. A lease for Onshore
seismic equipment was determined to be appropriately accounted for as an
operating lease, but a substantial penalty for early termination had not been
accrued through lease expense in accordance with US GAAP. Three other leases for
accounting software, a seismic vessel and a new seismic vessel engine were
determined to be inappropriately accounted for as operating leases, and a
restatement was recorded to reclassify the leases as capital leases. The
restatements affected the 2001 opening retained earnings balance. In addition,
the restatements affected lease expense (generally included in selling, general
and administrative costs or cost of sales), depreciation, interest expense,
capitalized costs and capital lease obligations for the year ended December 31,
2001.

  CEILING TEST FOR OIL AND NATURAL GAS ASSETS.

     The Company determined that a full cost ceiling test under the provisions
of SEC full cost accounting should have been performed for the oil and natural
gas assets owned by its subsidiary Atlantis for the year ended December 31,
2001. Current management is not able to find any evidence that such a test was
carried out. On this basis, a retroactive full cost ceiling test has been
performed and an impairment of the oil and natural gas assets for the year ended
December 31, 2001 was recognized.

 UK LEASES.

     The Company determined that the UK leases (Notes 2 and 19) were incorrectly
recorded and presented in its previously issued financial statements. In prior
years' financial statements, all gains were recognized under all these lease
transactions. Embedded in these gains were liabilities related to the difference
between the projected future distribution from the defeasance banks at inception
of the lease and the projected lease payments, based on forward interest rate
curves. This element should have been separated from the total gain, recorded as
a deferred gain and reduced the recognized gain. The deferred
                                       F-25
<PAGE>

gain related to the interest rate differential should have been amortized over
the term of the lease. In the previously issued financial statements, no such
gain deferrals were recorded. The restatements reduced the January 1, 2001
opening retained earnings balance. In addition, the restatements affected other
financial items for the year ended December 31, 2001.

     One of the vessels on such lease was acquired through the acquisition of
Awilco Floating Production AS in 1998. As a result, the restatements related to
the deferred gain also affected the goodwill in the 2001 opening balance sheet.
In addition, the remaining part of the deferred gain relating to the vessel
acquired from Awilco Floating Production AS was recognized in the 2000 net
income. However, as this was a deferred gain relating to a tax contingency, it
should have been recorded as an adjustment of goodwill. The 2001 opening balance
in retained earnings has been restated accordingly. In addition, the
restatements affected goodwill amortization for the year ended December 31,
2001.

  SECURITIZATION OF MULTI-CLIENT LIBRARY.

     The Company determined that the securitization transaction related to the
sale of a portion of its multi-client marine seismic library to a bankruptcy
remote, special purpose entity incorporated in Jersey in April 2001 was
incorrectly classified in the previously issued financial statements. The
special purpose entity should have been consolidated in the Company's financial
statements for the year ended December 31, 2001. The adjustment affected the
balance sheet for the year ended December 31, 2001 with a reclassification from
preferred securities to short term debt. In addition, a reclassification was
recorded in the 2001 statement of operations from minority interest expense to
financial expenses and selling, general and administrative expenses.

  TAXES.

     The Company determined that several restatements were necessary to properly
reflect deferred and payable taxes, including tax contingencies, in the 2001
opening retained earnings balance and in the consolidated financial statements
for the year ended December 31, 2001. This relates to adjustments for errors in
the calculation of the originally reported taxes and to tax effects of the other
restatements.

  OTHER ADJUSTMENTS.

     The Company identified and recorded several other restatements that
affected various captions in the statement of operations for the year ended
December 31, 2001 and in the 2001 opening retained earnings balance. The most
significant issues affecting the 2001 opening retained earnings balance and/or
net income for the year ended December 31, 2001 were as follows:

     - Restatements related to the correction of errors resulting from
       inappropriate cost capitalization and deferral of steaming, mobilization
       and yard stay costs both in the Marine Geophysical and the Onshore
       segments.

     - Restatements related to the correction of errors resulting from lack of
       accruals for social security taxes owed for crew-members on certain
       seismic vessels.

     - Restatements related to a number of erroneous accounting entries for
       several years prior to and including the year ended December 31, 2001,
       associated with a consolidated subsidiary.

     - Restatements related to the correction of an error in the fair value
       recognized for the TES contracts for the year ended December 31, 2001.

     - Restatements related to the recognition of a liability related to a
       settlement agreement with a customer in 2000. The restatement related to
       the loss accrual is recorded in the 2001 opening balance instead of in
       the 2001 statement of operations.

                                       F-26
<PAGE>

     Following is a presentation of the effects of the restatements described
above on the January 1, 2001 opening retained earnings balance and net income
(loss) for the year ended December 31, 2001:

<Table>
<Caption>
                                                       RETAINED EARNINGS   NET INCOME (LOSS)
                                                             AS OF            YEAR ENDED
                                                        JANUARY 1, 2001    DECEMBER 31, 2001
                                                       -----------------   -----------------
                                                             (IN THOUSANDS OF DOLLARS)
<S>                                                    <C>                 <C>
As Reported..........................................      $  94,410           $   4,453
Restatements:
  Revenue recognition................................        (25,297)             (2,697)
  Multi-client library (cost capitalization,
     impairment and amortization)....................       (100,214)            (37,649)
  FPSOs (cost capitalization, impairment and
     depreciation)...................................        (59,981)            (63,674)
  Asset retirement obligation for Banff field........         (7,060)             (3,356)
  Contract loss accruals.............................         40,132             (31,532)
  Lease accounting...................................         (4,980)            (23,269)
  Ceiling test for oil and natural gas assets........             --             (20,817)
  UK leases..........................................        (41,202)              1,163
  Taxes..............................................         53,825               3,208
  Other adjustments:
     Cost capitalization steaming, mobilization and
       yard stay.....................................         (8,173)            (11,493)
     Accrued social security taxes...................         (6,371)             (1,688)
     Errors in consolidated subsidiary...............        (11,542)              3,351
     Fair value of TES contracts.....................             --               8,885
     Settlement agreement with customer..............         (5,000)              5,000
     Various.........................................        (28,410)             (2,364)
                                                           ---------           ---------
As Restated..........................................      $(109,863)          $(172,479)
                                                           =========           =========
</Table>

                                       F-27
<PAGE>

     Following are the restated consolidated financial statements compared to
financial statements as reported (includes effect of changed presentation due to
discontinued operations):

CONSOLIDATED STATEMENT OF OPERATIONS

<Table>
<Caption>
                                                                     YEAR ENDED
                                                                  DECEMBER 31, 2001
                                                              -------------------------
                                                              AS RESTATED   AS REPORTED
                                                              -----------   -----------
                                                              (IN THOUSANDS OF DOLLARS,
                                                               EXCEPT PER SHARE DATA)
<S>                                                           <C>           <C>
Revenues Services...........................................   $ 893,230    $1,052,628
Revenues Products...........................................          --            --
                                                               ---------    ----------
          Total Revenues....................................     893,230     1,052,628
                                                               ---------    ----------
Cost of sales Services......................................     557,074       535,999
Cost of sales Products......................................          --            --
Depreciation and amortization...............................     336,480       334,506
Research and development costs..............................       3,752         3,752
Selling, general and administrative costs...................      61,999        78,305
Impairment of long-lived assets.............................      12,686        13,155
Other operating (income) expense............................    (125,559)     (119,067)
                                                               ---------    ----------
          Total operating expenses..........................     846,432       846,650
                                                               ---------    ----------
Operating profit............................................      46,798       205,978
Other income (expense):
  Loss from associated companies............................        (690)         (491)
  Interest expense..........................................    (151,624)     (143,179)
  Other financial items, net................................      (6,269)      (22,052)
                                                               ---------    ----------
  Income (loss) from continuing operations before minority
     interest, income taxes and discontinued operations.....    (111,785)       40,256
Minority expense (benefit)..................................          (4)           --
Income tax expense..........................................      28,344        35,803
                                                               ---------    ----------
  Income (loss) from continuing operations..................    (140,125)        4,453
Loss from discontinued operations, net of tax...............     (32,354)           --
                                                               ---------    ----------
          Net income (loss).................................   $(172,479)   $    4,453
                                                               =========    ==========
Basic and diluted income (loss) per share from continuing
  operations................................................   $   (1.36)   $     0.04
Discontinued operations.....................................       (0.32)           --
                                                               ---------    ----------
Basic and diluted net income (loss) per share...............   $   (1.68)   $     0.04
                                                               =========    ==========
</Table>

                                       F-28
<PAGE>

CONSOLIDATED BALANCE SHEET

<Table>
<Caption>
                                                                  DECEMBER 31, 2001
                                                              -------------------------
                                                              AS RESTATED   AS REPORTED
                                                              -----------   -----------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>           <C>
                                        ASSETS
Cash and cash equivalents...................................  $   78,604    $   94,062
Restricted cash.............................................      22,821         7,965
Accounts receivable, net....................................     146,508       147,867
Unbilled and other receivables..............................      43,488        85,638
Other current assets........................................      74,647        96,813
Assets of discontinued operations...........................     242,997       250,521
                                                              ----------    ----------
          Total current assets..............................     609,065       682,866
Multi-client library, net...................................     799,062       918,072
Property and equipment, net.................................   2,171,443     2,281,105
Restricted cash.............................................      10,014            --
Investments in associated companies.........................      13,316        20,713
Deferred tax assets.........................................     139,171       170,863
Goodwill and intangible assets, net.........................     173,038       195,654
Other long-lived assets.....................................      47,020        33,533
                                                              ----------    ----------
          Total assets......................................  $3,962,129    $4,302,806
                                                              ==========    ==========

                         LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt and current portion of long-term debt.......  $  400,086    $  236,498
Current portion of capital lease obligations................      14,275         9,931
Debt and other liabilities of discontinued operations.......      63,045        57,208
Accounts payable............................................      66,328        67,012
Accrued expenses............................................     232,144       206,756
Income taxes payable........................................       2,956        16,448
                                                              ----------    ----------
          Total current liabilities.........................     778,834       593,853
Long-term debt..............................................   1,913,585     1,903,571
Capital lease obligations...................................      51,303        41,683
Other long-term liabilities.................................      79,975        24,161
Deferred tax liabilities....................................      16,434        73,503
                                                              ----------    ----------
          Total liabilities.................................   2,840,131     2,636,771
                                                              ----------    ----------
Commitments and contingencies:
Minority interest in consolidated subsidiaries..............       1,101            --
Guaranteed preferred beneficial interest in PGS junior
  subordinated debt securities..............................     141,000       141,000
Mandatorily redeemable cumulative preferred stock related to
  multi-client securitization...............................          --       163,588
Shareholders' equity:
  Common stock..............................................      71,089        71,089
  Additional paid-in capital................................   1,225,115     1,225,115
  Retained earnings (deficit)...............................    (282,342)       98,863
  Other comprehensive income (loss).........................     (33,966)      (33,620)
                                                              ----------    ----------
          Total shareholders' equity........................     979,896     1,361,447
                                                              ----------    ----------
          Total liabilities and shareholders' equity........  $3,962,129    $4,302,806
                                                              ==========    ==========
</Table>

     Certain amounts have been reclassified to conform to the current balance
sheet presentation.

                                       F-29
<PAGE>

NOTE 5 -- IMPAIRMENT OF LONG-LIVED ASSETS AND OTHER OPERATING (INCOME) EXPENSE

     Impairments of long-lived assets consist of the following:

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY              PREDECESSOR COMPANY
                                          ------------   -----------------------------------
                                           TWO MONTHS    TEN MONTHS         YEARS ENDED
                                             ENDED          ENDED          DECEMBER 31,
                                          DECEMBER 31,   OCTOBER 31,   ---------------------
                                              2003          2003         2002        2001
                                          ------------   -----------   --------   ----------
                                                                                  (RESTATED)
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                       <C>            <C>           <C>        <C>
Multi-client library....................      $ --         $90,053     $200,393    $12,686
Production assets and equipment.........        --             328      331,971         --
Seismic assets and equipment............        --           3,539       16,706         --
Other long-lived assets.................        --           1,091        9,401         --
                                              ----         -------     --------    -------
          Total.........................      $ --         $95,011     $558,471    $12,686
                                              ====         =======     ========    =======
</Table>

     SFAS 121 was the applicable guidance for evaluating goodwill and long-lived
assets for impairment for 2001. In 2002 and 2003, impairment analyses for
long-lived assets were completed in accordance with SFAS 144 and for goodwill in
accordance with SFAS 142.

     Over the last three years, the Company's sales estimates for several of its
multi-client surveys have been revised downwards, resulting in impairments of
such surveys in 2001, 2002 and 2003. In 2002 the Company recorded an impairment
charge of $332.0 million relating to the FPSO Ramform Banff as a result of
negative development of the Banff field and decreased prospects for the
redeployment of the vessel to more profitable projects. Also in 2002, the
Company recorded $9.4 million (included in other long-lived assets above) of
impairment of goodwill in relation to its Marine Geophysical segment.

     In addition to impairments specified above, the Company adopted the
provisions of SFAS 142 on January 1, 2002 and recorded a $163.6 million
impairment of existing goodwill as a cumulative effect of a change in accounting
principle as described in note 2.

     Other operating (income) expense consists of the following:

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY             PREDECESSOR COMPANY
                                          ------------   ----------------------------------
                                           TWO MONTHS    TEN MONTHS        YEARS ENDED
                                             ENDED          ENDED          DECEMBER 31,
                                          DECEMBER 31,   OCTOBER 31,   --------------------
                                              2003          2003        2002        2001
                                          ------------   -----------   -------   ----------
                                                                                 (RESTATED)
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                       <C>            <C>           <C>       <C>
Gain from sale of subsidiary (Data
  Management) (Note 23).................     $   --        $    --     $    --   $(137,002)
Termination of employees and
  reorganization........................        582         19,235       9,570      11,443
Cost of 2001 re-audit and completion of
  2002 audit............................        470          2,089          --          --
Canceled merger gain, net (Veritas)
  (Note 23).............................         --             --      (2,864)         --
Other...................................         --             --       1,781          --
                                             ------        -------     -------   ---------
          Total.........................     $1,052        $21,324     $ 8,487   $(125,559)
                                             ======        =======     =======   =========
</Table>

                                       F-30
<PAGE>

NOTE 6 -- ACCOUNTS RECEIVABLE, NET

     Accounts receivable, net, consist of the following:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Accounts receivable -- trade................................   $130,821      $173,744
Allowance for doubtful accounts.............................     (3,115)       (4,608)
                                                               --------      --------
          Total.............................................   $127,706      $169,136
                                                               ========      ========
</Table>

     Development of allowance for doubtful accounts is as follows:

<Table>
<Caption>
                                            SUCCESSOR
                                             COMPANY             PREDECESSOR COMPANY
                                           ------------   ----------------------------------
                                            TWO MONTHS    TEN MONTHS        YEARS ENDED
                                              ENDED          ENDED            DECEMBER
                                           DECEMBER 31,   OCTOBER 31,   --------------------
                                               2003          2003        2002        2001
                                           ------------   -----------   -------   ----------
                                                                                  (RESTATED)
                                                       (IN THOUSANDS OF DOLLARS)
<S>                                        <C>            <C>           <C>       <C>
Beginning balance........................    $ 2,913        $ 4,648     $ 2,321    $ 3,353
New and additional allowances............        837          2,615       5,955      1,281
Write-offs and reversals.................       (179)        (4,350)     (3,616)    (2,313)
Disposal of subsidiary...................       (127)            --         (12)        --
                                             -------        -------     -------    -------
          Ending balance.................    $ 3,444        $ 2,913     $ 4,648    $ 2,321
                                             =======        =======     =======    =======
Presented as:
  Accounts receivable, net...............    $ 3,115        $ 2,472     $ 4,608    $ 2,160
  Unbilled and other receivables.........        329            314          --         --
  Assets of discontinued operations......         --            127          40        161
                                             -------        -------     -------    -------
          Total..........................    $ 3,444        $ 2,913     $ 4,648    $ 2,321
                                             =======        =======     =======    =======
</Table>

NOTE 7 -- OTHER CURRENT ASSETS

     Other current assets consist of the following:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Prepaid operating expenses..................................   $19,186       $23,815
Spare parts, consumables and supplies.......................    11,348         7,814
Prepaid taxes...............................................    11,017         3,274
Produced oil, not lifted....................................     4,569         2,748
Deferred steaming, mobilization.............................        --         7,713
Advances to agents..........................................     5,123           197
Other.......................................................    11,367         7,097
                                                               -------       -------
          Total.............................................   $62,610       $52,658
                                                               =======       =======
</Table>

                                       F-31
<PAGE>

NOTE 8 -- PROPERTY AND EQUIPMENT, NET

     The components of property and equipment, including property and equipment
under capitalized leases, are summarized as follows:

<Table>
<Caption>
                                                    SUCCESSOR COMPANY   PREDECESSOR COMPANY
                                                    -----------------   -------------------
                                                                 DECEMBER 31,
                                                    ---------------------------------------
                                                          2003                 2002
                                                    -----------------   -------------------
                                                           (IN THOUSANDS OF DOLLARS)
<S>                                                 <C>                 <C>
Seismic vessels and equipment.....................     $   384,294          $ 1,121,435
Production vessels and equipment..................         679,748            1,713,785
Fixtures, furniture and fittings..................          11,786               67,326
Buildings and other...............................           3,890               15,681
                                                       -----------          -----------
                                                         1,079,718            2,918,227
Accumulated depreciation..........................         (19,535)          (1,215,879)
                                                       -----------          -----------
          Total...................................     $ 1,060,183          $ 1,702,348
                                                       ===========          ===========
</Table>

     The Company had $656.6 million and $923.0 million in property and equipment
under UK leases at December 31, 2003 and 2002, respectively.

     When calculating impairments, the carrying values of assets or cash
generating units are compared to their recoverable amounts, defined as the
higher of estimated selling price and value in use. See Note 2 for further
description of the accounting policy for impairments of long-lived assets. As
seismic vessels and equipment are not separate cash-generating units, such
assets are presented combined. Vessels and equipment subject to capital leases
that are part of a cash-generating unit are no longer presented separately from
the year ended December 31, 2003.

     The following table summarizes depreciation expense, excluding impairments
(see note 5) and capitalized interest:

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY              PREDECESSOR COMPANY
                                          ------------   -----------------------------------
                                           TWO MONTHS    TEN MONTHS         YEARS ENDED
                                             ENDED          ENDED          DECEMBER 31,
                                          DECEMBER 31,   OCTOBER 31,   ---------------------
                                              2003          2003         2002        2001
                                          ------------   -----------   --------   ----------
                                                                                  (RESTATED)
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                       <C>            <C>           <C>        <C>
Depreciation expense, net of amounts
  capitalized into multi-client
  library...............................    $18,206       $121,485     $154,204    $140,698
Depreciation expense capitalized into
  multi-client library..................      1,329         11,766       31,528      30,234
Interest capitalized into property and
  equipment.............................    $    --       $     --     $     --    $  2,871
</Table>

     Significant impairment charges were recorded in each of the ten months
ended October 31, 2003 and the year ended December 31, 2002 related to property
and equipment. See Note 5.

                                       F-32
<PAGE>

NOTE 9 -- MULTI-CLIENT LIBRARY, NET

     The net carrying value of the multi-client library, by the year in which
the components were completed, is summarized as follows:

<Table>
<Caption>
                                                               SUCCESSOR     PREDECESSOR
                                                                COMPANY        COMPANY
                                                              ------------   ------------
                                                                     DECEMBER 31,
                                                              ---------------------------
                                                                  2003           2002
                                                              ------------   ------------
                                                               (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>            <C>
COMPLETED SURVEYS:
Completed during 1997, and prior years......................    $ 16,897       $ 17,700
Completed during 1998.......................................      20,527         31,052
Completed during 1999.......................................      40,402         64,064
Completed during 2000.......................................      40,140         99,837
Completed during 2001.......................................     139,154        227,758
Completed during 2002.......................................      54,520         80,617
Completed during 2003.......................................      74,686             --
                                                                --------       --------
  Completed surveys.........................................     386,326        521,028
Surveys in progress.........................................      21,679         62,831
                                                                --------       --------
Multi-client library........................................    $408,005       $583,859
                                                                ========       ========
</Table>

     The following table summarizes impairment charges, amortization and
capitalization of interest and depreciation related to the multi-client library:

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY              PREDECESSOR COMPANY
                                          ------------   -----------------------------------
                                           TWO MONTHS    TEN MONTHS         YEARS ENDED
                                             ENDED          ENDED          DECEMBER 31,
                                          DECEMBER 31,   OCTOBER 31,   ---------------------
                                              2003          2003         2002        2001
                                          ------------   -----------   --------   ----------
                                                      (IN THOUSANDS OF DOLLARS)   (RESTATED)
<S>                                       <C>            <C>           <C>        <C>
Impairment charges (note 5).............    $    --       $ 90,053     $200,393    $ 12,686
Amortization expense....................     33,347        148,399      195,954     182,123
Interest capitalized into multi-client
  library...............................        375          2,083        4,841      12,645
Depreciation capitalized into
  multi-client library..................    $ 1,329       $ 11,766     $ 31,528    $ 30,234
</Table>

     The application of the Company's minimum amortization requirements to the
components of the existing multi-client library is summarized as follows:

<Table>
<Caption>
                                                                  SUCCESSOR
                                                                   COMPANY
                                                               ----------------
                                                                MINIMUM FUTURE
                                                                AMORTIZATIONS
                                                               ----------------
                                                               (IN THOUSANDS OF
                                                                   DOLLARS)
<S>                                                            <C>
During 2004.................................................       $ 73,073
During 2005.................................................         96,393
During 2006.................................................         95,937
During 2007.................................................         77,925
During 2008.................................................         59,457
During 2009.................................................          5,220
                                                                   --------
Future minimum amortization.................................       $408,005
                                                                   ========
</Table>

                                       F-33
<PAGE>

     These minimum amortization requirements are calculated as if there will be
no future sales of these components. The Company believes that the likelihood of
incurring these minimum amortization amounts is remote because amortization
generated by multi-client sales in the ordinary course of business is expected
to substantially reduce the book value of the multi-client library.

     Because the minimum amortization requirements generally apply to the
multi-client library on a survey-by-survey basis rather than in the aggregate,
the Company may incur significant minimum amortization charges in a year even if
the aggregate amount of ordinary amortization charges recognized exceeds the
aggregate minimum amortization charges above.

NOTE 10 -- INTANGIBLE ASSETS, NET

     The components of intangible assets, net, are summarized as follows:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Existing technology.........................................   $33,011       $     --
Existing contracts..........................................    17,600             --
Order backlog...............................................     5,401             --
Patents, royalties and licenses.............................        85         20,230
                                                               -------       --------
          Total cost........................................    56,097         20,230
Accumulated amortization....................................    (3,488)       (14,893)
                                                               -------       --------
          Total.............................................   $52,609       $  5,337
                                                               =======       ========
</Table>

     Intangible assets existing at December 31, 2003 were primarily recognized
in conjunction with the adoption of fresh start reporting, effective November 1,
2003. Total amortization expense was $3.5 million for the two months ended
December 31, 2003, $1.5 million for the ten months ended October 31, 2003 and
$4.9 million and $8.3 million for the years ended December 31, 2002 and 2001,
respectively. The weighted remaining amortization period for intangible assets
as of December 31, 2004 is 6.2 years, and the amortization expense related to
these assets, under existing amortization plans, for the next five years is
$13.6 million (2004), $11.8 million (2005), $6.7 million (2006), $4.2 million
(2007) and $3.8 million (2008).

     At the Company's adoption of fresh start reporting, effective November 1,
2003, the Company established valuation allowances for deferred tax assets. If
such deferred tax assets, for which a valuation allowance is established, are
realized in a subsequent period, the tax effect will be recorded as a reduction
of the carrying value of intangible assets. Such reduction will reduce future
amortization expense related to these assets.

     As described in note 2, as of January 1, 2002, the Company recognized
$163.6 million in non-cash impairment charges of goodwill as a result of the
transition provisions of SFAS 142. In addition, in 2002, the Company recorded a
goodwill impairment charge of $9.4 million related to its Marine Geophysical
reporting unit due to identified impairment factors, which included a
significant reduction in the market value of the Company.

     In accordance with the provisions of SFAS 142, the Company did not
recognize any goodwill amortization during the year ended December 31, 2002 and
periods ended October 31 and December 31, 2003. Goodwill amortization for the
year ended December 31, 2001 was $5.2 million (excluding goodwill amortization
on operations presented as discontinued operations).

                                       F-34
<PAGE>

NOTE 11 -- OTHER LONG-LIVED ASSETS

     Other long-lived assets consist of the following:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Governmental grants and contractual receivables.............   $16,772       $17,238
Prepaid pension cost and long term receivables..............     6,947         9,400
Favorable lease contracts...................................    13,806            --
Deferred debt issue costs...................................        --        14,942
                                                               -------       -------
          Total.............................................   $37,525       $41,580
                                                               =======       =======
</Table>

     Governmental grants and contractual receivables relate to grants from the
Norwegian Government and contractual payments from FPSO contract counterparts
that the Company is entitled to receive to cover parts of its asset removal
obligations (note 2 and 13).

     The fair value of certain favorable lease contracts were recognized in the
Company's balance sheet in connection with the adoption of fresh start
reporting, effective November 1, 2003. The amortization of this asset over the
remaining lease period (which averages approximately 6 years) is recorded as an
increase of lease expense as part of cost of sales.

NOTE 12 -- ACCRUED EXPENSES

     Accrued expenses consist of the following:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Accrued employee benefits...................................   $ 30,199      $ 38,208
Accrued debt restructuring costs............................     25,218         1,166
Accrued vessel operating costs..............................     25,126        34,315
Customer advances and deferred revenue......................     12,614        35,236
Accrued severance costs.....................................      5,061         1,215
Accrued interest costs......................................      2,658        45,448
Other.......................................................     46,460        63,956
                                                               --------      --------
          Total.............................................   $147,336      $219,544
                                                               ========      ========
</Table>

     Accrued debt restructuring costs as of December 31, 2003 includes $22.7
million of excess cash (as defined in the Chapter 11 restructuring agreement)
payable to creditors of the Company under the restructuring agreement. The
amount was paid in May 2004.

                                       F-35
<PAGE>

     Changes in accrued severance and restructuring are as follows:

<Table>
<Caption>
                                             SUCCESSOR
                                              COMPANY             PREDECESSOR COMPANY
                                            ------------   ---------------------------------
                                             TWO MONTHS    TEN MONTHS        YEARS ENDED
                                               ENDED          ENDED         DECEMBER 31,
                                            DECEMBER 31,   OCTOBER 31,   -------------------
                                                2003          2003        2002       2001
                                            ------------   -----------   ------   ----------
                                                       (IN THOUSANDS OF DOLLARS)  (RESTATED)
<S>                                         <C>            <C>           <C>      <C>
Beginning balance.........................    $ 8,367       $  1,215     $   --     $   --
Additional allowances.....................      1,764         18,469      1,215         --
Severance and restructuring costs paid....     (5,070)       (11,317)        --         --
                                              -------       --------     ------     ------
          Ending balance..................    $ 5,061       $  8,367     $1,215     $   --
                                              =======       ========     ======     ======
</Table>

NOTE 13 -- OTHER LONG-TERM LIABILITIES

     Other long-term liabilities consist of the following:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Deferred gain and accrued liabilities UK leases (Note 19)...   $ 78,120      $ 26,636
Pension liability (Note 21).................................     45,185        12,623
Asset Retirement Obligations (Note 2).......................     50,016        58,215
Other.......................................................     24,342        26,722
                                                               --------      --------
          Total.............................................   $197,663      $124,196
                                                               ========      ========
</Table>

NOTE 14 -- SHORT-TERM DEBT AND CURRENT PORTION OF LONG-TERM DEBT

     Short-term debt and current portion of long-term debt consist of the
following:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Revolving bank credit facility(a)...........................   $    --      $  430,000
Bank credit facility........................................        --              48
Bank credit facility(a).....................................        --         250,000
Bank loan related to multi-client securitization program....        --          63,955
Current portion of long-term debt (see Note 15).............    18,512         261,058
                                                               -------      ----------
          Total.............................................   $18,512      $1,005,061
                                                               =======      ==========
</Table>

---------------

(a)  Debt compromised in the Chapter 11 proceeding.

     The revolving bank credit facility ($430 million) and the bank credit
facility ($250 million) had average interest rates as of December 31, 2002 of
1.94% and 5.92%, respectively.

                                       F-36
<PAGE>

NOTE 15 -- LONG-TERM DEBT

     Long-term debt consists of the following:

<Table>
<Caption>
                                                               SUCCESSOR    PREDECESSOR
                                                                COMPANY       COMPANY
                                                              -----------   ------------
                                                                     DECEMBER 31,
                                                              --------------------------
                                                                 2003           2002
                                                              -----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>           <C>
UNSECURED:
  10% Senior Notes, due 2010................................  $  745,950     $       --
  8% Senior Notes, due 2006.................................     250,000             --
  Debt compromised in the Chapter 11 proceeding.............          --      1,455,729
  LIBOR + 1.15% Unsecured senior term loan, due 2011........       4,811             --
SECURED:
  8.28% First Preferred Mortgage Notes, due 2011............     109,119        118,480
  Other loan, due 2006......................................      17,306          7,188
                                                              ----------     ----------
          Total debt........................................   1,127,186      1,581,397
  Less current portion......................................     (18,512)      (261,058)
                                                              ----------     ----------
          Total long-term debt..............................  $1,108,674     $1,320,339
                                                              ==========     ==========
</Table>

     Aggregate maturities of long-term debt as of December 31, 2003 are as
follows:

<Table>
<Caption>
                                                                 SUCCESSOR
                                                                  COMPANY
                                                               -------------
                                                               (IN THOUSANDS
                                                                OF DOLLARS)
<S>                                                            <C>
2004........................................................    $   18,512
2005........................................................        19,381
2006........................................................       263,586
2007........................................................        13,255
2008........................................................        14,394
Thereafter..................................................       798,058
                                                                ----------
          Total.............................................    $1,127,186
                                                                ==========
</Table>

     The 10% Senior Notes, due 2010 ("10% Notes") bear interest at 10% per annum
payable semi-annually and mature in November 2010 with no required principal
payments until then. The 10% Notes are not callable until November 2007 and are
callable thereafter at par plus a premium of 5% declining linearly until
maturity. The 8% Senior Notes, due 2006 ("8% Notes") bear interest at 8% payable
semi-annually and mature in November 2006 with no required principal payments
until then. The 8% Notes are callable from November 2003 at par plus a premium
of 3% declining linearly until maturity. Both the 10% Notes and 8% Notes are
unsecured obligations of PGS ASA and are guaranteed by certain material
subsidiaries.

     The 8.28% First Preferred Mortgage Notes, due 2011 ("8.28% Notes") bear
interest at 8.28% payable semi-annually to the bondholders along with scheduled
principal payments. The Company is required to make monthly sinking fund
payments to the indenture trustee in the amount of $50,000 per day. These
monthly payments are designed to meet semi-annual interest and principal
payments and are held in trust by the indenture trustee until the semi-annual
payments are made. The 8.28% Notes are secured by, among other things, two
seismic vessels. In addition the indenture trustee has an irrevocable deposit of
$10 million as security for future interest and principal payments; this deposit
is presented as long-term restricted cash in the consolidated balance sheet
because the monies will be used to make final debt service payment when the
8.28% Notes are retired. The 8.28% Notes are not callable until June 2006 and
are callable thereafter at par plus a make whole premium based on US treasury
rates plus 0.375%.

                                       F-37
<PAGE>

     In May 2004, the Company repaid its loan of $4.8 million, which had an
original maturity date in 2011.

  COVENANTS.

     In addition to customary representations and warranties, the Company's loan
and lease agreements include various covenants. Certain of the Company's debt
agreements contain covenants restricting it from incurring debt unless certain
coverage ratios are met and limiting financial indebtedness, excluding project
company debt, to $1.5 billion. These debt agreements also restrict, among other
things: payment of dividends; ability to place liens on assets; the amount of
subsidiary financial indebtedness; certain sale/leaseback transactions; certain
transactions with affiliates; investments in project companies; investment in
multi-client library; and asset dispositions.

     Certain of the loan and lease agreements and the senior note indenture
contain requirements to provide audited US GAAP financial statements by June 30
of each year and to provide unaudited US GAAP quarterly financial statements
within a specified period (typically 60 days) after the end of each of the first
three quarters. The Company received waivers and amendments allowing it to
report under Norwegian GAAP in lieu of US GAAP until June 30, 2005.

     The Company is in compliance with its loan covenants as of December 31,
2003 and currently.

  PLEDGED ASSETS.

     Seismic vessels and related equipment carrying a book value of $59.8
million and $106.0 million at December 31, 2003 and 2002, respectively, are
pledged as security for certain indebtedness.

  LETTER OF CREDIT AND GUARANTEES.

     The Company had aggregate outstanding letters of credit and related types
of guarantees that are not reflected in the accompanying consolidated financial
statements of $31.0 million and $9.5 million at December 31, 2003 and 2002,
respectively.

  SUBSEQUENT EVENT.

     In March 2004, the Company entered into a secured $110.0 million credit
facility with a bank, consisting of a $70.0 million revolving credit facility
and a $40.0 million letter of credit facility. The Company may borrow US dollars
under the revolving credit facility for working capital and general corporate
purposes, and the letter of credit facility can be utilized in various
currencies to obtain letters of credit to secure, among other things,
performance and bid bonds required in the Company's ongoing business. The credit
facility matures in March 2006 and is secured by certain assets. The interest
rate for borrowings under the credit facility is LIBOR plus 2%. The credit
facility is an obligation of PGS ASA and is guaranteed by certain material
subsidiaries.

                                       F-38
<PAGE>

NOTE 16 -- INTEREST EXPENSE

     Interest expense consists of the following:

<Table>
<Caption>
                                        SUCCESSOR
                                         COMPANY                PREDECESSOR COMPANY
                                       ------------   ---------------------------------------
                                        TWO MONTHS    TEN MONTHS
                                          ENDED          ENDED      YEARS ENDED DECEMBER 31,
                                       DECEMBER 31,   OCTOBER 31,   -------------------------
                                           2003          2003          2002          2001
                                       ------------   -----------   -----------   -----------
                                                                                  (RESTATED)
                                                     (IN THOUSANDS OF DOLLARS)
<S>                                    <C>            <C>           <C>           <C>
Interest expense, gross..............    $(17,245)     $(92,504)     $(143,168)    $(152,205)
Interest on trust preferred
  securities.........................          --        (8,536)       (14,974)      (14,935)
Interest capitalized.................         375         2,083          4,841        15,516
                                         --------      --------      ---------     ---------
          Total interest expense.....    $(16,870)     $(98,957)     $(153,301)    $(151,624)
                                         ========      ========      =========     =========
</Table>

NOTE 17 -- OTHER FINANCIAL ITEMS, NET

     Other financial items, net, consists of the following:

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY              PREDECESSOR COMPANY
                                          ------------   -----------------------------------
                                           TWO MONTHS    TEN MONTHS         YEARS ENDED
                                             ENDED          ENDED          DECEMBER 31,
                                          DECEMBER 31,   OCTOBER 31,   ---------------------
                                              2003          2003         2002        2001
                                          ------------   -----------   --------   ----------
                                                                                  (RESTATED)
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                       <C>            <C>           <C>        <C>
Interest income.........................    $ 1,050        $ 4,467     $  4,214    $ 5,577
Foreign currency loss...................     (5,208)        (4,286)     (10,915)    (1,717)
Gain (loss) on TES......................         --             --       45,264     (9,111)
Other...................................       (106)        (1,653)      (4,771)    (1,018)
                                            -------        -------     --------    -------
          Financial expense, net........    $(4,264)       $(1,472)    $ 33,792    $(6,269)
                                            =======        =======     ========    =======
</Table>

     During 1998 and 1999, the Company entered into forward foreign currency
exchange contracts known as tax equalization swaps ("TES") related to its senior
unsecured notes, its 8.28% First Preferred Mortgage Notes and its trust
preferred securities. In 2002, all outstanding TES contracts were terminated.
The changes in fair value of the TES for the years ending December 31, 2002 and
2001, are included in other financial items, net with $45.3 million and ($9.1)
million, respectively. Reference is made to discussion in note 2 -- Derivative
Financial Instruments.

NOTE 18 -- FAIR VALUE OF FINANCIAL INSTRUMENTS

     The carrying amounts of cash and cash equivalents, restricted cash,
accounts receivable, other current assets, accounts payable and accrued expenses
and other current liabilities approximate their respective fair values because
of the short maturities of those instruments. The carrying amounts and the
estimated fair values of other financial instruments are summarized as follows:

<Table>
<Caption>
                                          SUCCESSOR COMPANY         PREDECESSOR COMPANY
                                       ------------------------   ------------------------
                                          DECEMBER 31, 2003          DECEMBER 31, 2002
                                       ------------------------   ------------------------
                                        CARRYING                   CARRYING
                                        AMOUNTS     FAIR VALUES    AMOUNTS     FAIR VALUES
                                       ----------   -----------   ----------   -----------
                                                    (IN THOUSANDS OF DOLLARS)
<S>                                    <C>          <C>           <C>          <C>
Debt.................................  $1,127,186   $1,185,313    $2,325,400   $1,103,354
Trust preferred securities...........          --           --       142,322        7,648
</Table>

     The carrying amounts of the revolving bank credit facility approximate
their fair values. The fair values of the other long-term debt instruments and
trust preferred securities are estimated using quotes obtained from dealers in
such financial instruments.

                                       F-39
<PAGE>

NOTE 19 -- COMMITMENTS AND CONTINGENCIES

  LEASES.

     The Company has operating lease commitments expiring at various dates
through 2013. The Company also has capital lease commitments expiring at various
dates through 2008. Future minimum payments related to non-cancelable operating
and capital leases, with lease terms in excess of one year, existing at December
31, 2003 are as follows:

<Table>
<Caption>
                                                                  DECEMBER 31, 2003
                                                              --------------------------
                                                               OPERATING       CAPITAL
                                                                 LEASES        LEASES
                                                              ------------   -----------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>            <C>
2004........................................................    $ 50,398      $ 22,688
2005........................................................      26,962        30,935
2006........................................................      18,059        21,623
2007........................................................      16,800         6,882
2008........................................................      16,879         7,156
Thereafter..................................................      29,742            --
                                                                --------      --------
          Total.............................................    $158,840        89,284
                                                                ========
  Imputed interest..........................................                    (5,848)
                                                                              --------
Net present value of capital lease obligations..............                    83,436
  Current portion of capital lease obligations..............                   (19,963)
                                                                              --------
          Long-term portion of capital lease obligations....                  $ 63,473
                                                                              ========
</Table>

     Future minimum payments related to non-cancelable operating leases reflect
$11.0 million and $7.6 million in sublease income for 2004 and 2005,
respectively, related to a time-charter of one FPSO shuttle tanker to a third
party.

     The future minimum payments under the Company's operating leases relate to
the Company's operations as follows:

<Table>
<Caption>
                                                                  DECEMBER 31, 2003
                                                                  -----------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>
Marine seismic and support vessels..........................          $ 15,381
FPSO shuttle tankers........................................            77,388
Operations computer equipment...............................             5,760
Buildings...................................................            60,239
Fixtures, furniture and fittings............................                72
                                                                      --------
          Total.............................................          $158,840
                                                                      ========
</Table>

     Rental expense for operating leases, including leases with terms of less
than one year, was $12.2 million for the two months ended December 31, 2003,
$76.3 million for the ten months ended October 31, 2003, and $105.4 million and
$117.9 million for the years ended December 31, 2002 and 2001, respectively.
Rental expense for operating leases, net of sub-lease income related to a time
charter of two FPSO shuttle tankers to a third party, is as follows: $1.4
million for the two months ended December 31, 2003, $16.6 million for the ten
months ended October 31, 2003, and $21.7 million and $13.8 million for the years
ended December 31, 2002 and 2001, respectively.

  OTHER.

     The Company has contingencies resulting from litigation, other claims and
commitments incidental to the ordinary course of business. Management believes
that the probable resolution of such contingencies will not materially affect
the financial position, results of operations or cash flows of the Company.

                                       F-40
<PAGE>

  UK LEASES.

     The Company entered into capital leases from 1996 to 1998 relating to
Ramforms Challenger, Valiant, Viking, Victory and Vanguard; the FPSO Petrojarl
Foinaven; and the production equipment of the Ramform Banff for terms ranging
from 20-25 years. The Company has indemnified the Lessors for the tax
consequences resulting from changes in tax laws or interpretations thereof or
adverse rulings by the tax authorities ("Tax Indemnities") and for variations in
actual interest rates from those assumed in the leases. There are no limits on
either of these indemnities. Reference is also made to the description in note
2 -- UK Leases.

     The Lessors claim tax depreciation (capital allowances) on the capital
expenditures that were incurred for the acquisition of the leased asset. The UK
Inland Revenue ("Inland Revenue") has not signed off on the Lessors' claims to
capital allowances with respect to the Company's UK leases. The Company
understands that the Inland Revenue has generally deferred agreeing to the
capital allowances claimed under such leases pending the outcome of a case that
has been appealed to the UK House of Lords (the highest UK court of appeal). It
is generally believed that a ruling will be rendered late 2004. In that case,
the Inland Revenue is challenging capital allowances associated with a defeased
lease.

     For various reasons, including the fact that the Company's leases differ
qualitatively from the lease structure in the pending legal proceeding, the
Company believes it is unlikely that its leases will be successfully challenged
by the Inland Revenue. However, the Company cannot predict what, if any,
liability it may incur relating to the Tax Indemnities because it is not
possible to know what, if any, events will happen in the future that might
result in tax consequences for which the Lessors are indemnified.

     In addition, the Inland Revenue has raised a separate issue about the
accelerated rate at which tax depreciation is available under the UK lease
related to the Petrojarl Foinaven. If the Inland Revenue were successful in
challenging that rate, the Lessor would be liable for increased taxes on
Petrojarl Foinaven in early periods (and decreased taxes in later years), and
the Company's rentals would correspondingly increase (and then decrease).

     For fresh start reporting purposes, the Company has estimated and recorded
the fair value of the specific tax exposure related to defeased UK leases noted
above using a probability-weighted analysis and a range of possible outcomes.
The Company has, therefore, recorded a 16.7 million British Pounds Sterling
(approximately $28.3 million) liability as of November 1, 2003 in accordance
with the requirements of SOP 90-7. At December 31, 2003 this liability amounted
to 16.7 million British Pounds Sterling or $29.5 million.

     The Defeased Rental Payments are based on assumed Sterling LIBOR rates
between 8% and 9% (the "Assumed Interest Rates"). If actual interest rates are
greater than the Assumed Interest Rates, the Company receives rental rebates.
Conversely, if actual interest rates are less than the Assumed Interest Rates,
the Company pays rentals in excess of the Defeased Rental Payments (the
"Additional Required Rental Payments"). Over the last several years, the actual
interest rates have been below the Assumed Interest Rates. Prior to November 1,
2003, the Company had deferred a portion of a deferred gain (see Note 2 -- UK
Leases) representing the net present value of Additional Required Rental
Payments as of the inception of each lease. Such deferred gain was amortized
over the terms of the leases. Effective November 1, 2003, the Company adopted
fresh start reporting, and recorded a liability equal to the fair value of the
future Additional Required Rental Payments. Such fair value was estimated at the
net present value of the Additional Required Rental Payments based on forward
market rates for Sterling LIBOR and an 8% discount rate. This liability, which
is amortized based on future rental payments, amounted to 30.5 million British
Pounds Sterling (approximately $51.6 million) at November 1, 2003, and 27.4
million British Pounds Sterling (approximately $48.6 million) at December 31,
2003.

                                       F-41
<PAGE>

NOTE 20 -- INCOME TAXES

     The expense (benefit) for income taxes from continuing operations consists
of the following:

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY              PREDECESSOR COMPANY
                                          ------------   -----------------------------------
                                           TWO MONTHS    TEN MONTHS         YEARS ENDED
                                             ENDED          ENDED          DECEMBER 31,
                                          DECEMBER 31,   OCTOBER 31,   ---------------------
                                              2003          2003         2002        2001
                                          ------------   -----------   --------   ----------
                                                                                  (RESTATED)
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                       <C>            <C>           <C>        <C>
Current taxes:
  Norwegian.............................    $   394        $ 6,639     $     --    $  4,314
  Foreign...............................      1,558         15,373       23,801       2,579
Deferred taxes:
  Norwegian.............................     (1,575)         2,025      158,846     (77,048)
  Foreign...............................     (4,226)        (3,943)       3,243      98,499
                                            -------        -------     --------    --------
          Total.........................    $(3,849)       $20,094     $185,890    $ 28,344
                                            -------        -------     --------    --------
Classification in Consolidated
  Statements of Operations:
  Income tax expense (benefit)..........     (3,849)        21,911      185,890      28,344
  Fresh start adoption..................         --         (1,817)          --          --
                                            -------        -------     --------    --------
          Total income tax expense
            (benefit)...................    $(3,849)       $20,094     $185,890    $ 28,344
                                            -------        -------     --------    --------
</Table>

     The net expense (benefit) for the two months ended December 31, 2003, the
ten months ended October 31, 2003 and the years ended 2002 and 2001 include $3.1
million, $182.8 million, $61.0 million and $92.5 million, respectively, in
valuation allowance charges related to deferred tax assets (see table below).

     The net expense (benefit) for the ten months ended October 31, 2003 and the
years ended December 31, 2002 and 2001 include $2.0 million, $15.0 million and
$(16.2) million, respectively, related to the resolution of uncertainties
regarding outstanding tax issues.

     The net expense (benefit) for the years ended December 31, 2002 and 2001
exclude $9.6 million and $4.2 million, respectively, related to discontinued
operations.

     The Company evaluated the need for valuation allowances related to its
deferred tax assets by considering the evidence regarding the ultimate
realization of those recorded assets. The Company has recorded valuation
allowances for 100% of net deferred tax assets due to cumulative losses in
recent years and management's expectations about the generation of taxable
income from contracts that are currently in effect. Because of these cumulative
losses and future expectations, the Company has concluded that it was more
likely than not that the net deferred tax assets would not be realized and have
recognized the valuation allowances accordingly. The Company believes that it
has valid tax planning strategies that may ultimately be successful in utilizing
those net deferred tax assets. To the extent that the Company continues to
generate deferred tax assets, it will continue to assess the need for valuation
allowances related to those assets. Short term deferred tax asset that is
recognized in the Consolidated Balance Sheets without valuation allowance is
offset by long term deferred tax liabilities within the same tax jurisdiction.

                                       F-42
<PAGE>

     Changes in valuation allowance are as follows:

<Table>
<Caption>
                                              SUCCESSOR
                                               COMPANY              PREDECESSOR COMPANY
                                             ------------   ------------------------------------
                                              TWO MONTHS    TEN MONTHS         YEARS ENDED
                                                ENDED          ENDED           DECEMBER 31,
                                             DECEMBER 31,   OCTOBER 31,   ----------------------
                                                 2003          2003         2002        2001
                                             ------------   -----------   --------   -----------
                                                                                     (RESTATED)
                                                          (IN THOUSANDS OF DOLLARS)  -----------
<S>                                          <C>            <C>           <C>        <C>
Balance at the beginning of the period.....    $365,439      $182,581     $121,498    $ 28,907
  Additions................................       3,111       182,858       61,083      92,591
                                               --------      --------     --------    --------
Balance at the end of the period...........    $368,550      $365,439     $182,581    $121,498
                                               --------      --------     --------    --------
</Table>

     The expense (benefit) for income taxes from continuing operations differs
from the amounts computed when applying the Norwegian statutory tax rate to
income (loss) before income taxes as a result of the following:

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY                PREDECESSOR COMPANY
                                          ------------   ---------------------------------------
                                           TWO MONTHS    TEN MONTHS
                                             ENDED          ENDED      YEARS ENDED DECEMBER 31,
                                          DECEMBER 31,   OCTOBER 31,   -------------------------
                                              2003          2003          2002          2001
                                          ------------   -----------   ----------   ------------
                                                                                     (RESTATED)
                                                        (IN THOUSANDS OF DOLLARS)   ------------
<S>                                       <C>            <C>           <C>          <C>
Income (loss) from continuing operations
  before income taxes, minority
  interest, discontinued operations, and
  cumulative effect of change in
  accounting principles:
     Norwegian..........................    $(16,755)     $ 623,654    $(547,030)    $ (70,985)
     Foreign............................       3,198        (46,052)     (76,205)      (40,800)
                                            --------      ---------    ---------     ---------
          Total.........................     (13,557)       577,602     (623,235)     (111,785)
Norwegian statutory rate................          28%            28%          28%           28%
Expense (benefit) for income taxes at
  statutory rate........................      (3,796)      (161,729)    (174,506)      (31,300)
Increase (reduction) in income taxes
  from:
  Foreign earnings taxed at other than
     statutory rate.....................        (440)        (2,057)      (8,023)          (14)
  Petroleum surtax(a)...................      (1,619)         5,908       (2,503)           --
  Non taxable gain on debt discharge....          --       (351,078)          --            --
  Non-recurring taxes related to
     Norwegian shipping regime..........          --             --           --       (24,631)
  Exit Norwegian shipping regime 2002...          --             --       78,859            --
  Prior year adjustment in regards to
     exit Norwegian shipping regime
     2001...............................          --             --       82,141            --
  Goodwill impairment...................          --             --       48,462            --
  Taxable gain (loss) from local
     currency other than reporting
     currency...........................      (1,495)           372       91,020        (1,524)
  Other permanent items.................         390         22,362        9,357        (6,778)
  Deferred tax asset valuation
     allowance..........................       3,111        182,858       61,083        92,591
                                            --------      ---------    ---------     ---------
          Total income tax expense
            (benefit)...................    $ (3,849)     $  20,094    $ 185,890     $  28,344
                                            --------      ---------    ---------     ---------
</Table>

---------------

(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-43
<PAGE>

     Deferred tax assets and liabilities are summarized as follows:

<Table>
<Caption>
                                             SUCCESSOR COMPANY      PREDECESSOR COMPANY
                                           ---------------------   ---------------------
                                               DECEMBER 31,            DECEMBER 31,
                                                   2003                    2002
                                           ---------------------   ---------------------
                                                     (IN THOUSANDS OF DOLLARS)
                                             ASSET     LIABILITY     ASSET     LIABILITY
                                           ---------   ---------   ---------   ---------
<S>                                        <C>         <C>         <C>         <C>
Current assets...........................  $ (11,803)  $  2,188    $ (15,372)  $    920
Property, equipment and other long-lived
  assets.................................    (55,035)   120,585      (62,216)   247,427
Tax losses carried forward...............   (326,622)        --     (227,786)       281
Deferred gain (loss).....................    (63,419)    37,583      (69,263)    45,470
Tax credits..............................     (3,855)        --       (3,665)        --
Expenses deductible when paid............    (31,208)        --      (52,247)        --
Other temporary differences..............    (37,833)    13,773      (27,009)     4,091
                                           ---------   --------    ---------   --------
          Total deferred tax (asset)
            liability before valuation
            allowance....................   (529,775)   174,129     (457,558)   298,189
                                           ---------   --------    ---------   --------
Deferred tax asset valuation allowance...    368,550                 182,581
                                           ---------   --------    ---------   --------
          Deferred tax (asset)
            liability....................  $(161,225)  $174,129    $(274,977)  $298,189
                                           ---------   --------    ---------   --------
  Net deferred tax
     liability -- Norwegian..............                10,980                  10,520
  Net deferred tax
     liability -- Foreign................                 1,924                  12,692
                                                       --------                --------
          Net deferred tax liability.....              $ 12,904                $ 23,212
                                                       --------                --------
Classification in Consolidated Balance
  Sheets:
  Short-term deferred tax asset..........              $     --                $ (1,193)
  Short-term deferred tax liability......                 2,166                      --
  Long-term deferred tax liability.......                10,738                  24,405
                                                       --------                --------
          Net deferred tax liability.....              $ 12,904                $ 23,212
                                                       --------                --------
</Table>

     Norwegian tax loss carried forward of $618.1 million expire at various
dates from 2009 through 2013. Tax loss carried forward in the UK, Brazil,
Singapore and Australia totaling $510.5 million carry forward indefinitely. US
tax loss carried forward of $19.8 million expire between 2019 and 2023. It is
the Company's current policy not to provide Norwegian taxes on unremitted
earnings of certain international operations, which reflect full provision for
non-Norwegian income taxes, as these earnings are expected to be reinvested
indefinitely. As of December 31, 2003 and 2002, the Company did not have any
such unremitted earnings.

     A foreign subsidiary was until 2002 included in the Norwegian shipping tax
regime. No deferred taxes were recognized on unremitted earnings in this
subsidiary prior to the withdrawal from the regime as these earnings at that
time were expected to be reinvested indefinitely within the regime. The
subsequent decision to exit with effect from 2002 resulted in recognition of
deferred tax liabilities of $78.8 million. The Norwegian Central Tax Office
(CTO) has not yet finalized the 2002 tax assessment in relation to withdrawal
from the Norwegian shipping tax regime. The pending issue is related to fair
value of the vessels involved. The Company based such exit values on third party
valuations, while the CTO has raised the issue whether the Company's book values
at December 31, 2001, would be more appropriate as basis for computing the tax
effects of the exit. Any increase of exit values will result in an increase of
taxable exit gain and a corresponding increase in basis for future tax
depreciations. The Company estimates that if the CTO position is upheld, taxes
payable for 2002, without considering mitigating actions, could increase by up
to $24 million. The Company believes that its calculation basis for exit has
been prepared using acceptable principles and will contest any adjustment to
increase taxes payable.

                                       F-44
<PAGE>

NOTE 21 -- POST-RETIREMENT BENEFITS

     The Company sponsors defined benefit pension plans for substantially all of
its Norwegian and UK employees, with eligibility determined by certain
period-of-service requirements. These plans are generally funded through
contributions to insurance companies. It is the Company's general practice to
fund amounts to these defined benefit plans, which are sufficient to meet the
applicable statutory requirements. At December 31, 2003, 1,122 employees were
participating in these plans.

     Reconciliation of the plans' aggregate projected benefit obligations and
fair values of assets are summarized as follows:

     Change in projected benefit obligations:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Projected benefit obligations at beginning of period(a).....   $ 90,478      $46,111
Service cost................................................      1,204        7,928
Interest cost...............................................      1,207        3,108
Employee contributions......................................         --        1,503
Payroll tax.................................................      1,359        1,198
Actuarial (gain) loss, net..................................      3,338           64
Benefits paid...............................................         --       (2,022)
Exchange rate effects.......................................      4,269       15,443
                                                               --------      -------
          Projected benefit obligations at end of year......   $101,855      $73,333
                                                               ========      =======
</Table>

---------------

(a) Projected benefit obligations at beginning of period in the column for 2003
    refers to fresh start reporting as of November 1, 2003.

     Change in plan assets:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Fair value of plan assets at beginning of period(b).........   $50,134       $ 34,571
Return on plan assets.......................................       819          3,439
Employer contributions......................................       504         10,202
Employee contributions......................................        --          1,503
Amendments..................................................        --        (10,262)
Benefits paid...............................................        --         (2,022)
Exchange rate effects.......................................     1,875         10,713
                                                               -------       --------
          Fair value of plan assets at end of year..........   $53,332       $ 48,144
                                                               =======       ========
</Table>

---------------

(b) Fair value of plan assets at beginning of period in the column for 2003
    refers to fresh start reporting as of November 1, 2003.

                                       F-45
<PAGE>

     The aggregate funded status of the plans and amounts recognized in the
Company's balance sheets are summarized as follows:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Funded status...............................................   $(48,523)     $(24,358)
Unrecognized actuarial loss.................................      3,338        13,404
Unrecognized prior service cost.............................         --            25
Unrecognized transition obligation..........................         --           154
                                                               --------      --------
          Net amount recognized as accrued pension
            liability.......................................   $(45,185)     $(10,775)
                                                               ========      ========
</Table>

     Net amount recognized as accrued pension liability is presented as follows:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Other long-term assets......................................   $     --      $  1,848
Other long-term liabilities.................................    (45,185)      (12,623)
                                                               --------      --------
          Net amount recognized as accrued pension
            liability.......................................   $(45,185)     $(10,775)
                                                               ========      ========
</Table>

     The accumulated benefit obligation for all defined benefit pension plans
was $81.4 million and $55.9 million as of December 31, 2003 and 2002,
respectively.

     Assumptions used to determine benefit obligations:

<Table>
<Caption>
                                            DECEMBER 31, 2003             DECEMBER 31, 2002
                                       ---------------------------   ---------------------------
                                       PLAN I   PLAN II   PLAN III   PLAN I   PLAN II   PLAN III
                                       ------   -------   --------   ------   -------   --------
<S>                                    <C>      <C>       <C>        <C>      <C>       <C>
Discount rate........................   6.0%     6.0%       5.3%      6.5%     7.0%       5.5%
Return on plan assets................   7.0%     7.0%       7.5%      7.5%     8.0%       7.5%
Benefit increase.....................   3.0%     3.0%       4.7%      4.0%     3.3%       4.2%
Annual adjustment to pensions........   3.0%     3.0%       3.0%      3.3%     3.3%       2.5%
</Table>

     The measurement dates used to calculate the actuary measurements are
approximately one month prior to balance sheet dates.

                                       F-46
<PAGE>

     The aggregate net periodic pension costs for the Company's defined benefit
pension plans is summarized as follows.

<Table>
<Caption>
                                             SUCCESSOR
                                              COMPANY            PREDECESSOR COMPANY
                                            ------------   -------------------------------
                                             TWO MONTHS    TEN MONTHS       YEARS ENDED
                                               ENDED          ENDED        DECEMBER 31,
                                            DECEMBER 31,   OCTOBER 31,   -----------------
                                                2003          2003        2002      2001
                                            ------------   -----------   -------   -------
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                         <C>            <C>           <C>       <C>
Service cost..............................     $1,204        $ 7,145     $ 7,928   $ 7,641
Interest cost.............................      1,207          3,247       3,108     2,693
Expected return on plan assets............       (819)        (2,977)     (3,439)   (2,591)
Amortization of actuarial loss (gain).....        (80)           403       1,908        26
Amortization of prior service cost........         --              3           2         3
Amortization of transition obligation.....         --             17          15        14
Payroll tax...............................        266            397         367       347
                                               ------        -------     -------   -------
          Net periodic pension cost.......     $1,778        $ 8,235     $ 9,889   $ 8,133
                                               ======        =======     =======   =======
</Table>

     Information for pension plans with an accumulated benefit obligation in
excess of plan assets are as follows:

<Table>
<Caption>
                                                              SUCCESSOR    PREDECESSOR
                                                               COMPANY       COMPANY
                                                              ----------   ------------
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2003          2002
                                                              ----------   ------------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Projected benefit obligation................................   $89,819       $54,130
Accumulated benefit obligation..............................    72,151        40,744
Fair value of plan assets...................................    45,074        29,001
</Table>

     The Company's pension plan asset allocation at December 31, 2003 and 2002,
by asset category, are presented by major plan group as follows:

<Table>
<Caption>
                                   SUCCESSOR COMPANY             PREDECESSOR COMPANY
                              ----------------------------   ----------------------------
                                   DECEMBER 31, 2003              DECEMBER 31, 2002
                              ----------------------------   ----------------------------
                              PLAN I    PLAN II   PLAN III   PLAN I    PLAN II   PLAN III
                              -------   -------   --------   -------   -------   --------
                                               (IN THOUSANDS OF DOLLARS)
<S>                           <C>       <C>       <C>        <C>       <C>       <C>
Fair value of plan assets...  $15,280   $14,907   $23,145    $12,688   $12,508   $22,948
                              -------   -------   -------    -------   -------   -------
Bonds.......................       62%       57%       --         54%       59%       --
Equity securities...........       13%       14%       74%        11%        7%       97%
Other.......................       25%       29%       26%        35%       34%        3%
                              -------   -------   -------    -------   -------   -------
          Total.............      100%      100%      100%       100%      100%      100%
                              =======   =======   =======    =======   =======   =======
</Table>

     Substantially all employees not eligible for coverage under the defined
benefit plans described above are eligible to participate in other retirement
plans in accordance with local industrial, tax and social regulations. All of
these plans are considered defined contribution plans. Under the Company's US
defined contribution 401(k) plan, essentially all US employees are eligible to
participate upon completion of certain period-of-service requirements. The plan
allows eligible employees to contribute up to 15% of compensation, subject to
IRS and plan limitations, on a pre-tax basis. Employee pre-tax contributions are
matched by the Company up to 6% of compensation, with a 2003 statutory employee
contribution cap of $12,000. All contributions vest when made. The employer
matching contribution recognized by the Company related to the plan was $0.2
million for the two months ended December 31, 2003, $1.2 million for the ten
months ended October 31, 2003 and $1.2 million for each of the years ended
December 31, 2002 and 2001. Contributions to the plan by employees for these
periods were $0.6 million, $2.7 million, $3.8 million and $3.7 million,
respectively. Aggregate employer and employee contributions under the Company's
other plans for the two months ended December 31, 2003, the ten months ended
October 31,
                                       F-47
<PAGE>

2003 and the years ended December 31, 2002 and 2001 totaled $0.1 million and
$0.1 million (two months 2003), $2.1 million and $0.3 million (ten months 2003),
$7.4 million and $3.0 million (2002) and $4.9 million and $2.7 million (2001).

NOTE 22 -- SHARE BASED COMPENSATION PLANS

     In connection with the restructuring of the Company in 2003, all shares in
the Company were cancelled (see Notes 1 and 3 for additional information).
Accordingly, all agreements on share options for the Company's key employees and
directors were also cancelled. No new agreements have been established since the
restructuring. During the period in which the share-based compensation plan was
active, the exercise price of each award equalled the market price of the
Company's shares on the grant date. The vesting period for granted options
ranged from approximately three years to approximately three and one-half years.
Once vested, the exercisable life of the options was generally a two-year
period, with certain options granted during 2000 and forward exercisable over a
three-year period.

     A summary of the status of the Company's share-based compensation plans as
of December 31, 2003, 2002 and 2001, and changes during the years ended, is
summarized as follows:

<Table>
<Caption>
                                                      PREDECESSOR COMPANY
                                ---------------------------------------------------------------
                                                         DECEMBER 31,
                                ---------------------------------------------------------------
                                       2003                  2002                  2001
                                -------------------   -------------------   -------------------
                                           WEIGHTED              WEIGHTED              WEIGHTED
                                           AVERAGE               AVERAGE               AVERAGE
                                           EXERCISE              EXERCISE              EXERCISE
                                OPTIONS     PRICE     OPTIONS     PRICE     OPTIONS     PRICE
                                --------   --------   --------   --------   --------   --------
                                       (IN THOUSANDS OF OPTIONS, EXCEPT EXERCISE PRICES)
<S>                             <C>        <C>        <C>        <C>        <C>        <C>
Outstanding at beginning of
  year........................   4,973.5    NOK135     8,635.4    NOK142    10,690.8    NOK135
Granted.......................        --        --          --        --       120.0    NOK103
Exercised.....................        --        --          --        --       (98.0)   NOK 75
Forfeited/cancelled...........  (4,973.5)   NOK135    (3,661.9)   NOK151    (2,077.4)   NOK108
                                --------    ------    --------    ------    --------    ------
Outstanding at December 31....        --        --     4,973.5    NOK135     8,635.4    NOK142
                                ========    ======    ========    ======    ========    ======
Weighted average grant fair
  value of options granted
  during year.................                  --                    --                NOK 44
                                            ======                ======                ======
</Table>

     Exercisable options at December 31, 2002 and 2001 were 1,264,474 options at
a weighted average exercise price of NOK 117 and 4,611,404 options at a weighted
average exercise price of NOK 143, respectively.

NOTE 23 -- ACQUISITIONS AND DISPOSITIONS

     During 2001, the Company entered into a definitive business combination
agreement with Veritas DGC, Inc., but in 2002, the agreement was terminated. The
Company recognized a net gain of $2.9 million upon termination of the agreement
representing the excess of a termination payment received from Veritas over the
expenses incurred in connection with the proposed transaction. This amount was
recognized in 2002 in the consolidated statements of operations as other
operating (income) expense, net (see Note 5).

     In March 2001, the Company sold its global Petrobank data management
business and related software to Landmark Graphics Corporation, a subsidiary of
Halliburton Company, for $165.7 million in net cash proceeds. The Company
recognized a $137.0 million gain on the sale, net of taxes of $40.4 million.

     On December 11, 2002, the Company sold its Production Services (formerly
Atlantic Power Group) subsidiary to Petrofac Limited and recognized $26.8
million gross loss on disposal of this subsidiary in 2002, which included $35.4
million in goodwill impairments. The Company received proceeds of $20.2 million
at the closing date and received an additional $3.8 million and $1.5 million in
2003 upon

                                       F-48
<PAGE>

settlement of the working capital and certain contingent events, respectively.
Furthermore, the Company recorded fair value of $2.0 million in connection with
its adoption of fresh start reporting related to such contingent events as of
November 1, 2003. The Company is eligible to receive an additional $6.0 million
upon the occurrence of certain contingent events through 2010, which are not
recognized since the realization of such amount is uncertain.

     During February 2003, the Company sold its Atlantis oil and natural gas
activities to Sinochem, and received proceeds of $48.6 million in addition to
$10.6 million as reimbursements of outlays on behalf of Sinochem. The Company
may receive up to $25.0 million in additional, contingent proceeds, which
currently has not been recognized. During 2002, the Company recognized $174.1
million in impairment charges related to Atlantis, including the estimated loss
on disposal.

     On December 10, 2003, the Company sold its wholly owned software company
PGS Tigress (UK) Ltd. for deferred compensation of approximately $1.8 million,
payable during 2004 and 2007, and may receive additional, contingent proceeds
based on performance of that company through 2006. As of December 31, 2003, the
Company had not received any such proceeds. The Company recognized no net gain
or loss on the disposal of Tigress.

     In connection with the adoption of fresh start reporting, the Company has
recorded the fair value of all contingent proceeds from previous disposals.

                                       F-49
<PAGE>

     The results of operations, net assets and cash flows for the
above-mentioned subsidiaries have been presented as discontinued operations for
2003, 2002 and 2001, and are summarized as follows:

<Table>
<Caption>
                        SUCCESSOR
                         COMPANY                                    PREDECESSOR COMPANY
                       ------------   --------------------------------------------------------------------------------
                        TWO MONTHS    TEN MONTHS
                          ENDED          ENDED                           YEARS ENDED DECEMBER 31,
                       DECEMBER 31,   OCTOBER 31,   ------------------------------------------------------------------
                           2003          2003                     2002                              2001
                       ------------   -----------   --------------------------------   -------------------------------
                         TIGRESS        TIGRESS     TIGRESS   ATLANTIS                 TIGRESS   ATLANTIS   PRODUCTION
                                                                          PRODUCTION                         SERVICES
                                                                           SERVICES              (RESTATED)
                                                          (IN THOUSANDS OF DOLLARS)
<S>                    <C>            <C>           <C>       <C>         <C>          <C>       <C>        <C>
Revenue..............     $ 137         $ 1,107     $ 1,684   $  23,452   $ 181,302    $ 2,356   $    575   $ 166,990
                          -----         -------     -------   ---------   ---------    -------   --------   ---------
Operating expenses
  before
  depreciation,
  amortization,
  impairment and
  other operating
  income and
  expenses...........      (264)         (2,433)     (2,796)    (15,836)   (176,642)    (3,845)    (1,599)   (165,181)
Depreciation and
  amortization.......        --            (707)       (913)         --        (455)    (1,261)       (53)     (1,426)
Impairment of long-
  term assets........        --              --          --    (169,284)         --         --    (20,817)         --
Other operating
  income and
  expenses...........        --            (512)         --          --          --         --       (633)         --
                          -----         -------     -------   ---------   ---------    -------   --------   ---------
         Total
           operating
          expenses...      (264)         (3,652)     (3,709)   (185,120)   (177,097)    (5,106)   (23,102)   (166,607)
                          -----         -------     -------   ---------   ---------    -------   --------   ---------
Operating profit
  (loss).............      (127)         (2,545)     (2,025)   (161,668)      4,205     (2,750)   (22,527)        383
Financial expenses
  and other financial
  items, net.........        24          (1,237)     (1,278)      1,545         (74)    (1,144)    (2,310)        245
                          -----         -------     -------   ---------   ---------    -------   --------   ---------
Income (loss) before
  income taxes and
  change in
  accounting
  principle..........     $(103)        $(3,782)    $(3,303)  $(160,123)  $   4,131    $(3,894)  $(24,837)  $     628
                          =====         =======     =======   =========   =========    =======   ========   =========
Capital expenditures
  of discontinued
  operations.........     $  --         $   118     $   135   $  77,126   $     103    $   138   $ 54,103   $     226
                          -----         -------     -------   ---------   ---------    -------   --------   ---------
</Table>

                                       F-50
<PAGE>

     A reconciliation of income (loss) before income taxes and change in
accounting principles, as reported above, and loss from discontinued operations,
net of tax, as presented in the Consolidated Statements of Operations, is as
follows:

<Table>
<Caption>
                                                  SUCCESSOR              PREDECESSOR COMPANY
                                                   COMPANY      --------------------------------------
                                                 ------------       TEN
                                                  TWO MONTHS      MONTHS
                                                    ENDED          ENDED      YEARS ENDED DECEMBER 31,
                                                 DECEMBER 31,   OCTOBER 31,   ------------------------
                                                     2003          2003          2002         2001
                                                 ------------   -----------   ----------   -----------
                                                                                           (RESTATED)
                                                               (IN THOUSANDS OF DOLLARS)
<S>                                              <C>            <C>           <C>          <C>
Income (loss) from discontinued operations
  before income taxes and change in accounting
  principles...................................     $(103)        $(3,782)    $(159,295)    $(28,103)
Loss on disposal...............................       (32)                      (31,580)          --
Additional proceeds............................        --           1,500            --           --
Income tax benefit (expense)...................        --              --        (9,588)      (4,251)
Goodwill impairments SFAS 142, net of tax......        --              --          (674)          --
                                                    -----         -------     ---------     --------
  Loss from discontinued operations, net of
     tax.......................................     $(135)        $(2,282)    $(201,137)    $(32,354)
                                                    -----         -------     ---------     --------
</Table>

     The Company recorded $0.7 million in goodwill impairment relating to its
Tigress operations when implementing SFAS 142 as of January 1, 2002.

     Allocation of interest expense to discontinued operations is based on
actual interest charged to the respective entities.

     As of December 31, 2003, the Company had no assets related to discontinued
operations. As of December 31, 2002, the following assets and liabilities
related to discontinued operations:

<Table>
<Caption>
                                                              PREDECESSOR COMPANY
                                                              --------------------
                                                               DECEMBER 31, 2002
                                                              --------------------
                                                              TIGRESS    ATLANTIS
                                                              --------   ---------
                                                                (IN THOUSANDS OF
                                                                    DOLLARS)
<S>                                                           <C>        <C>
Cash and cash equivalents...................................  $   427    $  2,915
Accounts receivable, net....................................      810       3,489
Other current assets........................................      324       1,913
Property and equipment, net.................................      214         323
Oil and natural gas assets, net.............................       --      56,669
Other long-lived assets.....................................    1,684          --
                                                              -------    --------
          Total assets......................................  $ 3,459    $ 65,309
                                                              =======    ========
Short-term debt.............................................  $    --    $(15,800)
Accounts payable............................................     (437)       (451)
Accrued expenses............................................   (1,106)     (3,729)
                                                              -------    --------
          Total liabilities.................................  $(1,543)   $(19,980)
                                                              =======    ========
</Table>

     During August 2002, the Company purchased an aggregate 70% interest in PL
038 on the Norwegian Continental Shelf of the North Sea. The interest was
purchased from Statoil (which held a 28% interest in PL038) and Norsk Hydro
(which held a 42% interest in PL038). The Company's 30% partner is the Norwegian
government's State Direct Financial Interest. As consideration for the 70%
interest, the Company assumed a portion of the abandonment liabilities
associated with PL 038, estimated and accrued at $35.4 million, as well as any
future environmental liabilities that may be generated by exploration and
production activities in the field. The Company's FPSO vessel, Petrojarl Varg,
has been in production on the Varg field of the license since December 1998. The
transaction was accounted for as an asset purchase.

                                       F-51
<PAGE>

NOTE 24 -- RELATED PARTY TRANSACTIONS

     At December 31, 2003, 2002 and 2001, the Company owned 50% of the shares in
Geo Explorer AS and had chartered a vessel from that company during these years.
The Company also held 100% of the shares in Walther Herwig AS (until December
11, 2003, the Company held 50% of the shares, but increased its share as Walther
Herwig AS was de-merged) and chartered two vessels from that company in 2003,
2002 and 2001. Total lease expense recognized during the two months ended
December 31, 2003, the ten months ended October 31, 2003 and the years ended
December 31, 2002 and 2001 on these vessels was $1.1 million, $6.4 million, $8.9
million and $9.2 million, respectively. There are no remaining lease commitments
related to these investees as of December 31, 2003.

     As of December 31, 2003, the Chairman of the Board, Jens Ulltveit-Moe,
through Umoe AS, controlled a total of 1,912,444 shares in PGS ASA. Jens
Ulltveit-Moe became a major shareholder and took office as Chairman of the Board
in 2002. Jens Ulltveit-Moe also has a 60% ownership interest in Knutsen OAS
Shipping AS ("Knutsen"). Knutsen is chartering the MT Nordic Svenita and the MT
Nordic Yukon vessels from PGS on a time charter contract and paid $20.1 million
and $20.5 million to PGS under these contracts in 2003 and 2002, respectively.
PGS charters the vessels from an independent third party. The vessels were
chartered by PGS to shuttle the Banff field, but in 2001 were chartered to
Knutsen on terms approximating PGS's terms under the third-party lease, due to
low production on the Banff field. The vessel MT Nordic Yukon was redelivered by
PGS to the vessel owner in November 2003. In addition, PGS has a contract of
affreightment with Knutsen for transporting crude oil relating to the Banff
field and paid $2.4 million and $1.8 million to Knutsen under this contract in
2003 and 2002, respectively. Mr. Ulltveit-Moe is also the Chairman of Unitor
ASA, a company that from time to time provides the Company with equipment for
its vessels. During the years ended December 31, 2003 and 2002, the Company
hired a consultant from Umoe Invest AS, who became an employee of the Company in
2004.

NOTE 25 -- INVESTMENTS IN ASSOCIATED COMPANIES

     Income(loss) from associated companies accounted for using the equity
method is as follows:

<Table>
<Caption>
                                            SUCCESSOR
                                             COMPANY              PREDECESSOR COMPANY
                                           ------------   -----------------------------------
                                            TWO MONTHS    TEN MONTHS         YEARS ENDED
                                              ENDED          ENDED          DECEMBER 31,
                                           DECEMBER 31,   OCTOBER 31,   ---------------------
                                               2003          2003         2002        2001
                                           ------------   -----------   --------   ----------
                                                                                   (RESTATED)
                                                       (IN THOUSANDS OF DOLLARS)
<S>                                        <C>            <C>           <C>        <C>
Corporations and limited partnerships:
  Geo Explorer AS........................      $119         $1,425      $    142    $   619
  FW Oil Exploration LLC.................        --             --        (5,845)    (1,358)
  Ikdam Production SA....................        81            162        (3,561)       223
  Triumph Petroleum......................        --           (813)       (2,237)      (179)
General partnerships.....................        --             --            --          5
                                               ----         ------      --------    -------
          Total..........................      $200         $  774      $(11,501)   $  (690)
                                               ====         ======      ========    =======
</Table>

                                       F-52
<PAGE>

     Investments and advances to associated companies accounted for using the
equity method are as follows:

<Table>
<Caption>
                                                  EFFECT OF                                                     OWNERSHIP PERCENT
                        BOOK VALUE    SHARE OF   FRESH START   PAID-IN CAPITAL/      EQUITY       BOOK VALUE          AS OF
                       DECEMBER 31,    INCOME    ADJUSTMENTS     (DIVIDENDS)      TRANSACTIONS   DECEMBER 31,     DECEMBER 31,
                           2002         2003        2003             2003           2003 (A)         2003             2003
                       ------------   --------   -----------   ----------------   ------------   ------------   -----------------
                                                               (IN THOUSANDS OF DOLLARS)
<S>                    <C>            <C>        <C>           <C>                <C>            <C>            <C>
Corporations and
  limited
  partnerships:
  Geo Explorer AS....    $ 1,630       $1,544       $  --            $ --           $    --         $3,174             50.0%
  Triumph
    Petroleum(b).....      2,793         (813)         --              --            (1,980)            --              0.0%
  Ikdam Production,
    SA...............      4,712          243        (265)             --                --          4,690             40.0%
  Walter Herwig
    AS(c)............      1,107           --          --              --            (1,107)            --            100.0%
Others...............        132           --          --              --                --            132
General
  partnerships.......         84           --          --               4               (14)            74
                         -------       ------       -----            ----           -------         ------
         Total.......    $10,458       $  974       $(265)           $  4           $(3,101)        $8,070
                         =======       ======       =====            ====           =======         ======
</Table>

---------------

(a)  Includes foreign currency translation differences.

(b)  The Company's interest in Triumph Petroleum was sold in July 2003.

(c)  The Company increased the ownership percentage to 100% in Walter Herwig AS
     in December 2003. As of December 31, 2003, Walter Herwig AS is therefore
     consolidated in the financial statements.

NOTE 26 -- SEGMENT AND GEOGRAPHIC INFORMATION

     In 2003, the Company revised its organizational structure. Prior to 2003,
PGS was organized and managed as two business segments, geophysical and
production. Due to the increased size and importance of certain businesses
within these segments and in order to improve its management structure, the
Company now manages its overall business in four 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 the Company's onshore
       multi-client library;

     - Production, which owns and operates four harsh environment FPSO vessels
       in the North Sea and owns a 40% equity investment in Ikdam production,
       SA; and

     - Pertra, a small oil and natural gas company that owns 70% of and is the
       operator for PL 038 on the Norwegian Continental Shelf ("NCS") and also
       owns participating interests in two additional NCS licenses in areas that
       do not have current production.

     All segment information presented below has been restated to reflect this
revision in the organization structure. The Company manages its Marine
Geophysical segment from Lysaker, Norway, its Onshore segment from Houston,
Texas, and its Production segment and Pertra from Trondheim, Norway.

     The principal markets for the Production segment are the UK and Norway.
Pertra produces its oil in Norwegian waters, but oil is sold as a commodity
worldwide. The Varg field (in PL 038), which is 70% owned and operated by
Pertra, is produced using the FPSO Petrojarl Varg, which is owned and operated
by the Company's Production segment. The Marine Geophysical and Onshore segments
serve a worldwide market. Customers for all segments are primarily composed of
major multi-national, independent and national or state-owned oil companies.
Corporate overhead has been presented under Global Services/ Corporate.
Significant charges, which do not relate to the operations of any segment, such
as debt restructuring costs, are also presented as Global Services/Corporate.
Information related to operations held

                                       F-53
<PAGE>

for sale/discontinued operations during any period presented has been separately
aggregated. Affiliated sales are made at prices that approximate market value.
Interest and income tax expense is not included in the measure of segment
performance.

     Information by business segment is summarized as follows:

<Table>
<Caption>
                                                                                                 ELIMINATION
                                                                                      GLOBAL         OF
                                     MARINE                                          SERVICES/   AFFILIATED
                                   GEOPHYSICAL   ONSHORE    PRODUCTION    PERTRA     CORPORATE      SALES        TOTAL
                                   -----------   --------   ----------   ---------   ---------   -----------   ----------
                                                                 (IN THOUSANDS OF DOLLARS)
<S>                                <C>           <C>        <C>          <C>         <C>         <C>           <C>
REVENUE, UNAFFILIATED COMPANIES:
2003 (Successor -- two months)...  $   99,283    $ 21,459   $   39,745   $   9,544   $  2,340     $     --     $  172,371
2003 (Predecessor -- ten
  months)........................     498,719     128,965      210,437     112,097     11,646           --        961,864
2002 (Predecessor)...............     587,229     118,698      291,762      32,697     12,845           --      1,043,231
2001 (Predecessor) restated......     486,097      98,535      290,394          --     18,204           --        893,230
REVENUE, INCLUDES AFFILIATES:
2003 (Successor -- two months)...  $   99,382    $ 21,459   $   45,229   $   9,544   $  4,957     $ (8,200)    $  172,371
2003 (Predecessor -- ten
  months)........................     500,113     128,965      250,058     112,097     16,243      (45,612)       961,864
2002 (Predecessor)...............     587,640     118,698      306,645      32,697     16,022      (18,471)     1,043,231
2001 (Predecessor) restated......     486,375      98,535      290,394          --     19,472       (1,546)       893,230
DEPRECIATION AND AMORTIZATION:
2003 (Successor -- two months)...  $   37,342    $  5,904   $   10,441   $     743   $  1,269     $     --     $   55,699
2003 (Predecessor -- ten
  months)........................     191,215      29,425       43,418      30,826      6,692           --        301,576
2002 (Predecessor)...............     247,933      28,408       70,958      12,695      7,509           --        367,503
2001 (Predecessor) restated......     233,837      13,879       80,759          --      8,005           --        336,480
IMPAIRMENT OF LONG-LIVED ASSETS:
2003 (Successor -- two months)...  $       --    $     --   $       --   $      --   $     --     $     --     $       --
2003 (Predecessor -- ten
  months)........................      89,598       5,085          328          --         --           --         95,011
2002 (Predecessor)...............     220,594       5,906      331,971          --         --           --        558,471
2001 (Predecessor) restated......       9,054       3,632           --          --         --           --         12,686
OTHER (INCOME) EXPENSE, NET:
2003 (Successor -- two months)...  $    1,189    $     38   $       --   $      --   $   (175)    $     --     $    1,052
2003 (Predecessor -- ten
  months)........................       8,107         266           --          --     12,951           --         21,324
2002 (Predecessor)...............       1,341       2,625           --          --      4,521           --          8,487
2001 (Predecessor) restated......    (135,112)      2,175        3,706          --      3,672           --       (125,559)
OPERATING PROFIT (LOSS):
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
2002 (Predecessor)...............    (188,532)    (21,791)    (246,601)     (9,204)   (22,481)          --       (488,609)
2001 (Predecessor) restated......      96,495     (38,897)      18,344          --    (29,144)          --         46,798
LOSS FROM DISCONTINUED
  OPERATIONS, NET OF TAX:(a)
2003 (Successor -- two months)...  $     (135)   $     --   $       --   $      --   $     --     $     --     $     (135)
2003 (Predecessor -- ten
  months)........................      (3,782)         --        1,500          --         --           --         (2,282)
2002 (Predecessor)...............      (3,977)         --      (22,660)   (174,500)        --           --       (201,137)
2001 (Predecessor) restated......      (6,528)         --         (250)    (25,576)        --           --        (32,354)
CUMULATIVE EFFECT OF CHANGE IN
  ACCOUNTING PRINCIPLES, NET OF
  TAX
2003 (Successor -- two months)...  $       --    $     --   $       --   $      --   $     --     $     --     $       --
2003 (Predecessor -- ten
  months)........................        (779)         --        3,168          --         --           --          2,389
2002 (Predecessor)...............          --          --     (161,106)         --     (2,532)          --       (163,638)
INVESTMENT IN ASSOCIATED
  COMPANIES:
December 31, 2003 (Successor)....  $    3,308    $     --   $    4,687   $      --   $     75     $     --     $    8,070
December 31, 2002
  (Predecessor)..................       2,953       2,793        4,712          --         --           --         10,458
</Table>

                                       F-54
<PAGE>

<Table>
<Caption>
                                                                                                 ELIMINATION
                                                                                      GLOBAL         OF
                                     MARINE                                          SERVICES/   AFFILIATED
                                   GEOPHYSICAL   ONSHORE    PRODUCTION    PERTRA     CORPORATE      SALES        TOTAL
                                   -----------   --------   ----------   ---------   ---------   -----------   ----------
                                                                 (IN THOUSANDS OF DOLLARS)
<S>                                <C>           <C>        <C>          <C>         <C>         <C>           <C>
ASSETS OF DISCONTINUED
  OPERATIONS:
December 31, 2003 (Successor)....  $       --    $     --   $       --   $      --   $     --     $     --     $       --
December 31, 2002
  (Predecessor)..................       3,459          --           --      65,309         --           --         68,768
ASSETS, EXCLUDING DISCONTINUED
  OPERATIONS:
December 31, 2003 (Successor)....  $  959,261    $117,383   $  790,316   $  67,068   $ 63,332     $     --     $1,997,360
December 31, 2002
  (Predecessor)..................   1,299,984     119,535    1,168,634      75,648    107,168           --      2,770,969
ADDITIONS TO LONG-LIVED TANGIBLE
  ASSETS:(b)
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
2002 (Predecessor)...............     167,400      24,981        3,828      10,913      1,203           --        208,325
2001 (Predecessor) restated......     184,790      12,665      122,753                  1,356           --        321,564
CAPITAL EXPENDITURES ON
  DISCONTINUED OPERATIONS:(A)
2003 (Successor -- two months)...  $       --    $     --   $       --   $      --   $     --     $     --     $       --
2003 (Predecessor -- ten
  months)........................         118          --           --          --         --           --            118
2002 (Predecessor)...............         135          --          103      77,126         --           --         77,364
2001 (Predecessor) restated......         138          --          226      54,103         --           --         54,467
</Table>

---------------

(a)  Loss from discontinued operations, net of tax, and capital expenditures on
     discontinued operations, included in segment data for Pertra, relates to
     Atlantis, which was a part of the Company's oil and natural gas operations
     prior to its disposition in early 2003. The discontinued operations related
     to Tigress and Production services are related to Marine Geophysical and
     Production, respectively.

(b)  Consists of cash investments in multi-client library and capital
     expenditures.

     Since the Company provides services worldwide to the oil and natural gas
industry, a substantial portion of the property and equipment is mobile, and the
respective locations at the end of the period (as listed in the table below,
together with multi-client library and oil and natural gas assets, excluding
assets held for sale) are not necessarily indicative of the earnings of the
related property and equipment during the period. The geographic classification
of income statement amounts listed below is based upon location of performance
or, in the case of multi-client seismic data sales, the area where the survey
was physically located.

                                       F-55
<PAGE>

     Information by geographic region is summarized as follows:

<Table>
<Caption>
                                                                                                         ELIMINATION
                                                                                                             OF
                                                                                          MIDDLE EAST/   AFFILIATED
                               AMERICAS      UK       NORWAY    ASIA/PACIFIC    AFRICA       OTHER          SALES        TOTAL
                               --------   --------   --------   ------------   --------   ------------   -----------   ----------
                                                                   (IN THOUSANDS OF DOLLARS)
<S>                            <C>        <C>        <C>        <C>            <C>        <C>            <C>           <C>
REVENUE, UNAFFILIATED
  COMPANIES:
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
2002 (Predecessor)...........  235,010     275,706    227,104      154,821       80,393      70,197             --      1,043,231
2001 (Predecessor)
  restated...................  188,851     212,773    188,470      148,077       75,553      79,506             --        893,230
REVENUE, INCLUDES AFFILIATES:
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
2002 (Predecessor)...........  235,610     278,611    230,022      154,851       80,393      70,197         (6,453)     1,043,231
2001 (Predecessor)
  restated...................  190,159     215,144    190,647      148,294       75,553      79,506         (6,073)       893,230
TOTAL ASSETS:
December 31, 2003
  (Successor)................  $430,972   $870,941   $539,935     $111,484     $ 20,567     $23,461        $    --     $1,997,360
CAPITAL EXPENDITURES (CASH):
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
2002 (Predecessor)...........   10,776      17,073     28,415          192           --         279             --         56,735
2001 (Predecessor)
  restated...................    5,290      69,919     71,637          208          312         170             --        147,536
</Table>

     Export sales from Norway to unaffiliated customers did not exceed 10% of
gross revenue for the years ended December 31, 2003, 2002 and 2001.

     For the years ended December 31, 2003, 2002 and 2001, customers exceeding
10% of the Company's total revenue were as follows (the table shows percentage
of revenues accounted for by such customers, and the segments that had sales to
the respective customers are marked with X):

<Table>
<Caption>
                                                     YEARS ENDED DECEMBER 31,
                                              ---------------------------------------
                                                   2003           2002        2001
                                              ---------------   ---------   ---------
SEGMENTS SERVING CUSTOMER:                    19%   12%   10%   15%   11%   14%   11%
--------------------------                    ---   ---   ---   ---   ---   ---   ---
<S>                                           <C>   <C>   <C>   <C>   <C>   <C>   <C>
Marine Geophysical..........................   X     X     X     X     X     X     X
Onshore.....................................               X
Production..................................   X     X           X     X     X     X
Pertra......................................   X                       X
Global Services/Corporate...................   X                 X     X     X     X
</Table>

     In certain of the regions where the Company operates, a significant share
of its employees is organized in labor unions. Similarly the Company's
operations in certain regions are members of employer unions. Therefore, the
Company may be affected by labor conflicts involving such labor and employer
unions.

NOTE 27 -- SUPPLEMENTAL CASH FLOW INFORMATION

     Cash paid during the year includes payments for:

<Table>
<Caption>
                                           SUCCESSOR
                                            COMPANY              PREDECESSOR COMPANY
                                          ------------   ------------------------------------
                                           TWO MONTHS    TEN MONTHS
                                             ENDED          ENDED      YEARS ENDED DECEMBER,
                                          DECEMBER 31,   OCTOBER 31,   ----------------------
                                              2003          2003         2002         2001
                                          ------------   -----------   ---------   ----------
                                                                                   (RESTATED)
                                                       (IN THOUSANDS OF DOLLARS)
<S>                                       <C>            <C>           <C>         <C>
Interest, net of capitalized interest...    $19,619       $120,162     $112,543     $143,265
Interest on trust preferred
  securities............................         --             --       10,377       13,836
Income taxes............................      4,951          8,145       15,938        1,257
</Table>

                                       F-56
<PAGE>

     The Company entered into capital lease agreements for new equipment
aggregating $0.6 million for the ten months ended October 31, 2003, $65.0
million and $41.8 million for the years ended December 31, 2002 and 2001,
respectively. There were no new capital lease agreements during the two months
ended December 31, 2003.

NOTE 28 -- SUMMARIZED FINANCIAL INFORMATION FOR SUBSIDIARIES WITH DEBT
SECURITIES

     PGS Geophysical AS, a Norwegian corporation, is a wholly owned subsidiary
of the Company. PGS Geophysical AS is the largest geophysical 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. The Company has
fully and unconditionally guaranteed PGS Geophysical AS charter obligations in
connection with certain debt securities issued in order to finance the purchase
of these vessels. Summarized financial information for PGS Geophysical AS and
its consolidated subsidiaries is presented below. This information was derived
from the financial statements prepared on a stand-alone basis in conformity with
US GAAP. Separate financial statements and other disclosures with respect to PGS
Geophysical AS are omitted because the information contained therein, in light
of the information contained in the consolidated financial statements of the
Company, would not be material.

     The PGS Geophysical AS summarized financial information consists of the
following:

<Table>
<Caption>
                                         SUCCESSOR
                                          COMPANY               PREDECESSOR COMPANY
                                        ------------   --------------------------------------
                                         TWO MONTHS    TEN MONTHS
                                           ENDED          ENDED      YEAR ENDED DECEMBER 31,
                                        DECEMBER 31,   OCTOBER 31,   ------------------------
                                            2003          2003          2002         2001
                                        ------------   -----------   ----------   -----------
                                                                                  (RESTATED)
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                     <C>            <C>           <C>          <C>
Income Statement Data:
  Revenue.............................   $  17,610      $ 244,605    $ 286,261     $ 237,793
  Operating loss......................     (26,009)        (4,238)     (52,245)     (113,762)
  Net loss............................     (12,671)        (6,752)     (47,887)      (99,712)
Balance Sheet Data:
  Current assets......................   $  99,453      $ 141,008    $ 146,061     $ 121,609
  Noncurrent assets...................     148,951        123,182      157,137       168,054
  Current liabilities.................      84,523         82,555      112,941        95,618
  Noncurrent liabilities..............     408,479        416,699      385,920       320,473
  Equity (deficit)....................    (244,598)      (235,064)    (195,663)     (126,428)
</Table>

     Both Oslo Explorer PLC ("Explorer") and Oslo Challenger PLC ("Challenger"),
Isle of Man public limited 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 AS pursuant to long-term bareboat charters. Explorer and
Challenger are jointly and severally liable under the 8.28% First Preferred
Mortgage Notes (see note 15), in an original principal amount of $165.7 million,
which were issued to finance the purchase of the Ramform Explorer and the
Ramform Challenger. Summarized financial information for each of Explorer and
Challenger is presented below. This information was derived from the financial
statements prepared on a stand-alone basis in conformity with US GAAP. Separate
financial statements and other disclosures with respect to Explorer and
Challenger are omitted because the information, in light of the information
contained in the consolidated financial statements of the Company, would not be
material.

                                       F-57
<PAGE>

     The Oslo Explorer PLC and Oslo Challenger PLC summarized financial
information consists of the following:

<Table>
<Caption>
                                                                           PREDECESSOR COMPANY
                            SUCCESSOR COMPANY     ---------------------------------------------------------------------
                          ---------------------                                     YEARS ENDED DECEMBER 31,
                            TWO MONTHS ENDED        TEN MONTHS ENDED      ---------------------------------------------
                            DECEMBER 31, 2003       OCTOBER 31, 2003              2002                    2001
                          ---------------------   ---------------------   ---------------------   ---------------------
                          EXPLORER   CHALLENGER   EXPLORER   CHALLENGER   EXPLORER   CHALLENGER   EXPLORER   CHALLENGER
                          --------   ----------   --------   ----------   --------   ----------   --------   ----------
                                                                                                       (RESTATED)
                                                            (IN THOUSANDS OF DOLLARS)
<S>                       <C>        <C>          <C>        <C>          <C>        <C>          <C>        <C>
Income Statement Data:
  Revenue...............  $ 1,183     $ 1,177     $ 6,032     $ 6,003     $ 7,458     $ 7,421     $ 7,681     $ 7,643
  Operating profit......    1,167       1,159       5,885       5,857       7,295       7,259       7,534       7,496
  Net income............      361         355       1,738       1,708       2,094       2,058       1,608       1,570
Balance Sheet Data:
  Current assets........  $    --     $    --     $    --     $    --     $    --     $    --     $    --     $    --
  Non-current assets....   69,295      69,031      72,964      72,719      71,879      71,651      74,099      73,906
  Current liabilities...    6,252       6,252       7,616       7,616       5,864       5,864       5,535       5,532
  Non-current
    liabilities.........   49,658      49,657      52,324      52,336      54,729      54,729      59,373      59,373
  Equity................   13,385      13,122      13,024      12,767      11,286      11,058       9,191       9,001
</Table>

NOTE 29 -- SUPPLEMENTAL INFORMATION -- OIL AND GAS RESERVES AND COSTS
(UNAUDITED)

     Pertra has proved oil reserves associated with its 70% interest in PL 038
on the NCS. The Company, through its Marine Geophysical segment, also owns some
small overriding royalty interests in oil and natural gas production offshore in
the US Gulf of Mexico. The supplemental financial and oil and natural gas
reserve information and standardized measure of future cash flows from proved
reserves are presented for Pertra only, The overriding royalties financial
results and oil and natural reserves are not considered material for disclosure.
In addition, Pertra employs a Company FPSO to produce oil from PL 038. The
revenues and expenses are eliminated in consolidation, but the expenses are
presented gross for this supplemental presentation. As a result, the oil and
natural gas results in this supplemental disclosure will not match the results
in the consolidated statements of operations.

  FINANCIAL RESULTS RELATED TO OIL AND NATURAL GAS ACTIVITIES

     The Successor results of operations, capitalized costs and costs incurred
are based on using the successful efforts method of accounting for oil and
natural gas activities. The Predecessor results of operations and costs incurred
are based on the SEC full cost method. See Note 2 for the description of each
method. These methods may create significant differences in results, primarily
because of the capitalization policies of each method. As a result, the
Successor and Predecessor results of operations, capitalized costs and costs
incurred information is not comparable.

                                       F-58
<PAGE>

     Results of operations relating to oil and natural gas producing activities
are as follows:

<Table>
<Caption>
                                                    SUCCESSOR COMPANY   PREDECESSOR COMPANY
                                                    -----------------   -------------------
                                                    TWO MONTHS ENDED     TEN MONTHS ENDED
                                                    DECEMBER 31, 2003    OCTOBER 31, 2003
                                                    -----------------   -------------------
                                                           (IN THOUSANDS OF DOLLARS)
<S>                                                 <C>                 <C>
Oil revenues......................................       $ 9,544             $112,097
Production costs..................................         6,354               62,296
Other operating costs.............................           604                2,136
Accretion of asset retirement obligation..........           271                1,821
Exploration costs.................................         4,344
Depletion, depreciation and amortization..........           739               30,815
                                                         -------             --------
          Net income (loss) before tax............        (2,767)              15,028
                                                         -------             --------
          Income tax expense (benefit)............        (2,159)              11,722
                                                         -------             --------
          Net income (loss).......................       $  (609)            $  3,306
                                                         =======             ========
</Table>

     The above table does not include any amounts for allocated selling, general
and administrative expense or finance income or expense.

     Capitalized costs relating to oil and natural gas producing activities are
set forth below:

<Table>
<Caption>
                                                               SUCCESSOR COMPANY
                                                               -----------------
                                                               DECEMBER 31, 2003
                                                               -----------------
                                                               (IN THOUSANDS OF
                                                                   DOLLARS)
<S>                                                            <C>
Capitalized Costs:
  Proved properties.........................................        $30,262
  Unproved properties.......................................          4,000
  Accumulated depreciation, depletion and amortization......           (739)
                                                                    -------
          Net...............................................        $33,523
                                                                    =======
</Table>

     As a supplemental disclosure, under the full cost method the depletion,
depreciation and amortization rate for the Predecessor 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 gas exploration
and development activities:

<Table>
<Caption>
                                                    SUCCESSOR COMPANY   PREDECESSOR COMPANY
                                                    -----------------   -------------------
                                                    TWO MONTHS ENDED     TEN MONTHS ENDED
                                                    DECEMBER 31, 2003    OCTOBER 31, 2003
                                                    -----------------   -------------------
                                                           (IN THOUSANDS OF DOLLARS)
<S>                                                 <C>                 <C>
Exploration costs.................................       $13,262              $16,253
Development costs.................................         4,375               10,318
                                                         -------              -------
          Total costs incurred....................       $17,637              $26,571
                                                         =======              =======
</Table>

  PROVED RESERVES AND STANDARDIZED MEASURE

     The estimates of proved oil and natural gas reserves for Pertra as of
December 31, 2003 and 2002, were prepared by the Company's engineers in
accordance with guidelines established by the SEC and the FASB, which require
that reserve estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations except by
contractual arrangements. The December 31, 2003 estimates were reviewed by an
independent reservoir engineering consultant. All of Pertra's proved reserves
are located in the Norwegian North Sea. The reserve estimates as of December 31,
2003 and 2002 utilize respective oil prices of $29.97 and $28.86 per barrel
(reflecting adjustments for oil quality). The Company's actual average sale
price for oil produced in 2003 was $29.37 per barrel.

                                       F-59
<PAGE>

     Oil and natural gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. Reserve estimates are inherently imprecise, and estimates of new
discoveries are more imprecise than those of currently producing oil and natural
gas properties. Accordingly, these estimates are expected to change as
additional information becomes available in the future.

     The oil and natural gas proved reserve quantities and changes in reserve
quantities, the Standardized Measure of Future Net Cash Flows from Proved
Reserves (Standardized Measure) and the changes in Standardized Measure are
presented for the year ended December 31, 2003 and as of December 31, 2003. A
company is required to disclose this information when it has significant oil and
natural gas exploration and production activities. The Company meets the
significant activities requirement for 2003, but did not meet the requirement
for 2002 or 2001. As a result, only 2003 information is presented. In addition,
it is not considered material to the disclosure to present the changes in
reserves or the changes in Standardized Measure for the Predecessor and
Successor periods during 2003.

     The following tables provide a roll-forward of total proved reserves for
the year ended December 31, 2003, as well as proved developed reserves at year
end, as of the beginning and end of each respective year, the Standardized
Measure as of December 31, 2003 and the changes in Standardized Measure for the
year ended December 31, 2003:

ESTIMATED QUANTITIES OF RESERVES (UNAUDITED)

<Table>
<Caption>
                                                              DECEMBER 31,
CRUDE OIL                                                         2003
---------                                                     ------------
                                                              (IN THOUSAND
                                                                BARRELS)
<S>                                                           <C>
Proved Reserves:
  Beginning of the year.....................................      4,137
     Extensions and discoveries.............................      4,669
     Purchases of producing properties......................         --
     Revisions of previous estimates........................      3,067
     Sales of producing properties..........................         --
     Production.............................................     (4,056)
                                                                 ------
  End of year...............................................      7,818
                                                                 ======
Proved Developed Reserves:
  Beginning of year.........................................      3,272
                                                                 ======
  End of year...............................................      2,114
                                                                 ======
</Table>

                                       F-60
<PAGE>

STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS FROM PROVED RESERVES (UNAUDITED)

<Table>
<Caption>
                                                                   AS OF
                                                               DECEMBER 31,
                                                                   2003
                                                               -------------
                                                               (IN THOUSANDS
                                                                OF DOLLARS)
<S>                                                            <C>
Future cash inflows.........................................     $234,300
Future production costs.....................................      109,010
Future development costs....................................       12,900
Future abandonment costs....................................       37,122
Future income taxes.........................................       59,906
Future net cash flows.......................................       15,362
                                                                 --------
  Discount at 10% per annum.................................         (369)
                                                                 --------
Standardized Measure........................................     $ 15,731
                                                                 ========
</Table>

CHANGES IN STANDARDIZED MEASURE (UNAUDITED)

<Table>
<Caption>
                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                                   2003
                                                               -------------
                                                               (IN THOUSANDS
                                                                OF DOLLARS)
<S>                                                            <C>
Standardized Measure at beginning of year...................     $    944
                                                                 --------
  Revisions of reserves proved in prior years...............       49,280
  Changes in prices and production costs....................          333
  Changes in estimates of future development and abandonment
     costs..................................................      (10,760)
  Net change in income taxes................................      (59,090)
  Accretion of discount.....................................           94
  Other, primarily timing of production.....................          695
  Extensions, discoveries and other additions, net of future
     production and development cost........................       75,102
  Sales of oil and natural gas produced, net of production
     costs..................................................      (48,667)
  Previously estimated development and abandonment costs
     incurred during the period.............................        7,800
                                                                 --------
Net changes in Standardized Measure.........................       14,787
                                                                 --------
Standardized Measure at end of year.........................     $ 15,731
                                                                 ========
</Table>

                                       F-61
<PAGE>

                                 EXHIBIT INDEX

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
           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 Ex-
                            hibit(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 Nos. 33-61500 and 333-10856))
           2.4           -- Indenture dated as of November 5, 2003, among the
                            Company, each of the guarantors named therein and Law
                            Debenture Trust Company of New York, as trustee (the
                            "Trustee")
           2.5           -- First Supplemental Indenture, dated as of November 5,
                            2003, among the Company, each of the guarantors named
                            therein and the Trustee
           2.6           -- Second Supplemental Indenture, dated as of June 4, 2004,
                            among the Company, each of the guarantors named therein
                            and the Trustee
</Table>

        The Company and its consolidated subsidiaries are party to several debt
        instruments under which the total amount of securities authorized does
        not exceed 10% of the total assets of the Company and its subsidiaries
        on a consolidated basis. Pursuant to paragraph 2(b)(i) of the
        instructions to the exhibits to Form 20-F, the Company agrees to furnish
        a copy of such instruments to the SEC upon request.

<Table>
<C>                      <S>
           4.1           -- Employment agreement dated November 4, 2002 between the
                            Company and Svein Rennemo (the "Employment Agreement")
           4.2           -- Addendum to the Employment Agreement dated June 8, 2004
                            between the Company and Svein Rennemo
           4.3           -- 2004 CEO Bonus Scheme
           8.1           -- Subsidiaries (included in Item 4 of the annual report)
          11.1           -- Code of Conduct
          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
          15.2           -- Remuneration Committee Charter
</Table>