<PAGE>

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

                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, 2001

                                       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:

<Table>
<Caption>
             TITLE OF EACH CLASS                  NAME OF EACH EXCHANGE ON WHICH REGISTERED
             -------------------                  -----------------------------------------
<S>                                             <C>
American Depositary Shares, each representing              New York Stock Exchange
one ordinary share of nominal value NOK 5 per
                    share
PGS Trust I 9 5/8% Trust Preferred Securities              New York Stock Exchange
</Table>

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

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

     As of December 31, 2001, the number of ordinary shares, nominal value NOK 5
per share, outstanding was 103,345,987.

     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 item the registrant has
elected to follow.

                        Item 17 [ ]          Item 18 [X]
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

                           PETROLEUM GEO-SERVICES ASA

                       ANNUAL REPORT ON FORM 20-F FOR THE
                      FISCAL YEAR ENDED DECEMBER 31, 2001

                               TABLE OF CONTENTS

<Table>
<Caption>
                                                                        PAGE
                                                                        ----
<S>       <C>                                                           <C>
US Dollar Presentations...............................................    2
Where You Can Find More Information...................................    2
Forward-Looking Information...........................................    3

                                   PART I
ITEM 1.   Identity of Directors, Senior Management and Advisors.......    4
ITEM 2.   Offer Statistics and Expected Timetable.....................    4
ITEM 3.   Key Information.............................................    4
ITEM 4.   Information on the Company..................................   12
ITEM 5.   Operating and Financial Review and Prospects................   35
ITEM 6.   Directors, Senior Management and Employees..................   51
ITEM 7.   Major Shareholders and Related Party Transactions...........   55
ITEM 8.   Financial Information.......................................   56
ITEM 9.   The Offer and Listing.......................................   57
ITEM 10.  Additional Information......................................   58
ITEM 11.  Quantitative and Qualitative Disclosures About Market          66
            Risk......................................................
ITEM 12.  Description of Securities Other than Equity Securities......   66

                                  PART II
ITEM 13.  Defaults, Dividend Arrearages and Delinquencies.............   67
ITEM 14.  Material Modifications to the Rights of Security Holders and   67
            Use of Proceeds...........................................

                                  PART III
ITEM 17.  Financial Statements........................................   67
ITEM 18.  Financial Statements........................................   67
ITEM 19.  Exhibits....................................................   67
</Table>

                            US DOLLAR PRESENTATIONS

     In this Form 20-F, references to "US 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.

                      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 to this annual report, 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 reports and other information with the SEC. Reports and
other information we file with the SEC, including this annual report on Form
20-F, may be inspected and copied at the public reference facilities of the SEC
at 450 Fifth Street N.W., Washington D.C. 20549.

     You can also obtain copies of this material by mail from the Public
Reference Room of the SEC, 450 Fifth Street, N.W., Washington, D.C. 20549, at
prescribed rates. The SEC's telephone number is

                                        2
<PAGE>

1-800-SEC-0330. Additionally, information that we file electronically with the
SEC may also be obtained from its Internet site at http://www.sec.gov.

                          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:

     - the repayment or refinancing of debt and the effects of possible credit
       rating downgrades

     - liquidity and future cash flows

     - future capital expenditures and investments in our geophysical and
       production assets, including Atlantis-related development costs, and
       future investments in our multi-client library

     - market conditions, technological developments and other trends in the
       seismic data industry

     - business strategies

     - maintaining and obtaining contracts for our floating production, storage
       and offloading vessels

     - acquisition of contract and multi-client seismic data

     - licensing activities in Norway, West Africa and the Asia Pacific region

     - amortization charges for our multi-client library

     - expected future sales of seismic data

     - utilization and upgrading of our seismic vessels and equipment, including
       the Ramform Banff

     - future operating results and financial condition

     These 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

     - are based on many assumptions, 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 elsewhere in this
annual report. We will not update these statements unless the securities laws
require us to do so. Please read "Key Information -- Risk Factors" in Item 3 of
this annual report.

                                        3
<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 United States generally accepted
accounting principles, our selected consolidated financial data for the
five-year period ended December 31, 2001. Independent accountants have audited
our financial statements for each of the five years in the period ended December
31, 2001. From these consolidated financial statements, we have derived the
financial data presented below for such periods and as of such dates. You should
read the financial data for the three-year period ended December 31, 2001 and as
of December 31, 2001 and 2000 in conjunction with, and the financial data are
qualified in their entirety by reference to, our financial statements and notes
included in Item 18 of this annual report. Our financial statements and related
notes as of and for the years ended December 31, 2000, 1999 and 1998 have
previously been restated in our Form 20-F/A dated February 15, 2002 as described
in note 24 to our financial statements included in Item 18 of this annual report
to:

     - reflect fair value accounting for tax equalization swap contracts entered
       into in 1998 and 1999 to hedge our exposure to Norwegian taxes arising
       out of the conversion, for Norwegian tax purposes, of our US dollar
       denominated debt into Norwegian kroner

     - reflect the adoption of Staff Accounting Bulletin ("SAB") No. 101,
       "Revenue Recognition in Financial Statements", which became effective
       January 1, 2000, to our revenue recognition policy for some types of
       volume seismic data licensing arrangements

The financial data presented below and in our financial statements and related
notes included in Item 18 of this annual report as of and for those years have
been further restated as described in note 24 to:

     - properly capitalize interest cost associated with the upgrade of floating
       production, storage and offloading vessels

     - properly reflect property and equipment, multi-client library and
       depreciation and amortization related to two of our seismic vessels

     - reflect uncertainties regarding the future utilization of deferred tax
       assets in the form of a valuation allowance against these tax assets

     - properly amortize multi-client library in accordance with our minimum
       amortization policy

     - properly amortize deferred assets over their useful lives and accrue
       defined benefit pension obligations, commission/royalty liabilities and
       lease liabilities as incurred

     We have presented earnings before interest, taxes, depreciation and
amortization and unusual items, or EBITDA, in the table to provide additional
information about our financial performance. Our management uses EBITDA as a
supplemental financial measurement in the evaluation of our business. You should
not consider EBITDA as an alternative to net income, as an indicator of
operating performance or as an alternative to cash flows as a measure of
liquidity.

                                        4
<PAGE>

<Table>
<Caption>
                                                              YEARS ENDED DECEMBER 31(1)
                                      --------------------------------------------------------------------------
                                          2001           2000            1999            1998           1997
                                      ------------   -------------   -------------   -------------   -----------
                                                        (IN THOUSANDS, EXCEPT FOR SHARE DATA)
                                                     (AS RESTATED)   (AS RESTATED)   (AS RESTATED)
<S>                                   <C>            <C>             <C>             <C>             <C>
STATEMENT OF OPERATIONS DATA
  Revenue...........................  $  1,052,628   $    913,482     $   788,160     $   761,762    $   539,381
  Operating profit (loss)...........       205,978       (231,494)         39,072         143,968        126,356
  Income (loss) before extraordinary
    charge and cumulative effect of
    accounting change(2)(3).........         4,453       (204,960)        (13,839)        107,684         77,584
                                      ------------   ------------     -----------     -----------    -----------
  Extraordinary charge, net of
    tax(2)..........................            --             --              --              --         (3,447)
  Cumulative effect of accounting
    change, net of tax(3)...........            --         (6,555)        (19,977)             --             --
                                      ------------   ------------     -----------     -----------    -----------
  Net income (loss).................  $      4,453   $   (211,515)    $   (33,816)    $   107,684    $    74,137
                                      ============   ============     ===========     ===========    ===========
  Operating profit (loss) per share:
    Basic...........................  $       2.00   $      (2.27)    $      0.41     $      1.75    $      1.96
    Diluted.........................  $       2.00   $      (2.27)    $      0.41     $      1.70    $      1.88
  Income (loss) per share before
    extraordinary charge and
    cumulative effect of accounting
    change(2)(3):
    Basic...........................  $       0.04   $      (2.01)    $     (0.15)    $      1.31    $      1.20
    Diluted.........................  $       0.04   $      (2.01)    $     (0.15)    $      1.27    $      1.15
  Net income (loss) per share:
    Basic...........................  $       0.04   $      (2.07)    $     (0.36)    $      1.31    $      1.15
    Diluted.........................  $       0.04   $      (2.07)    $     (0.36)    $      1.27    $      1.10
  Basic shares outstanding..........   102,768,283    102,020,830      94,767,967      82,260,652     64,519,503
  Diluted shares outstanding........   102,788,055    102,020,830      94,767,967      84,794,836     67,358,004
BALANCE SHEET DATA (END OF PERIOD)
  Total assets......................  $  4,302,806   $  4,278,706     $ 4,184,997     $ 3,426,627    $ 1,677,848
  Multi-client library, net.........       918,072        848,720         816,423         553,415        325,181
  Total long-term debt and capital
    lease obligations...............     1,945,254      2,171,981       1,998,530       1,421,670        550,450
  Mandatorily redeemable preferred
    subsidiary securities...........       163,588             --              --              --             --
  Guaranteed preferred beneficial
    interest in subordinated debt
    securities......................       141,000        140,050         139,164              --             --
  Capital stock.....................     1,296,204      1,286,426       1,278,999       1,058,811        580,991
  Shareholders' equity..............     1,361,447      1,349,978       1,568,417       1,393,238        811,347
OTHER DATA
  EBITDA(4).........................  $    434,572   $    397,875     $   367,503     $   443,504    $   318,049
  Cash flows from operating
    activities......................       211,702        158,157         200,678         274,656        228,686
  Capital expenditures..............       239,623        115,217         667,869         521,630        468,872
  Investment in multi-client
    library.........................       230,166        264,541         338,718         388,228        203,267
</Table>

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

(1) We have made some reclassifications to conform prior year amounts with the
    current year presentation. We restated our fiscal 2000, 1999 and 1998
    financial statements as described in note 24 of the notes to our financial
    statements. The effects of the restatements for the years ended December 31,
    2000, 1999 and 1998 were net, non-cash charges of $23.9 million, $17.5
    million and $3.9 million, respectively.

(2) During March 1997, we prepaid our $30 million 7.12% senior notes due
    February 2004 and our $95 million 7.33% senior notes due February 2006. As a
    result, we incurred an extraordinary charge of $3.4 million, net of tax
    benefits of $1.3 million. The extraordinary charge consisted of a write-off
    of the associated debt issuance costs and the prepayment premium.

                                        5
<PAGE>

(3) Effective January 1, 2000, we adopted SAB No. 101. Application of this SAB
    required that we defer revenue recognition on some types of volume seismic
    data licensing arrangements until we have entered into a license agreement
    for specific data with the customer. Accordingly, we recognized a charge to
    income of $6.6 million, net of tax benefits of $2.5 million, as the
    cumulative effect of the change in accounting principle. Effective January
    1, 1999, we adopted Statement of Position ("SOP") 98-5, "Reporting on the
    Costs of Start-up Activities." This SOP requires that the initial, one-time
    costs related to introducing new products and services, conducting business
    in new territories or commencing new operations be expensed as incurred.
    Accordingly, we have recognized a charge to income of $20.0 million, net of
    tax benefits of $8.1 million, for the year ended December 31, 1999 as the
    cumulative effect of the change in accounting principle.

(4) We define EBITDA for this purpose as operating profit before depreciation
    and amortization and unusual items.

RISK FACTORS

     You should carefully consider the risks described below. The risks and
uncertainties described below are not the only ones facing our company.
Additional risks and uncertainties not presently known to us or that we
currently do not believe are material may also impair our financial condition or
our business operations. 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 shares could decline
significantly.

RISK FACTOR RELATING TO OUR PENDING TRANSACTIONS INVOLVING VERITAS DGC INC. AND
OUR ATLANTIS SUBSIDIARY

We may not be able to complete our pending combination transaction with Veritas
or the pending sale of our Atlantis subsidiary.

     Both of these transactions include conditions to closing that depend on the
actions of third parties and are therefore outside of our control. In addition,
the Veritas transaction is itself conditioned on closing the Atlantis sale. As a
result, we may not be able to complete these transactions or the transactions
could be delayed. If we fail to complete the sale of Atlantis, we could suffer
adverse consequences, including a downgrade of our debt and trust preferred
securities credit ratings by one or more credit rating agencies. If we fail to
complete the transaction with Veritas, we could suffer similar adverse
consequences. Please read "Information on the Company -- Recent
Developments -- Combination with Veritas" and "-- Sale of Atlantis" in Item 4,
"Operating and Financial Review and Prospects  --  Financial
Condition -- Capital Resources and Liquidity" in Item 5 and note 3 of the notes
to our financial statements in Item 18 of this annual report.

RISK FACTORS RELATING TO OUR FINANCIAL CONDITION

Our debt could be downgraded by one or more rating agencies.

     As of May 3, 2002, Moody's Investors Service, Inc. had rated our senior
unsecured debt at Baa3, its lowest investment grade credit rating, and had
placed that credit rating under review for possible downgrade. At that date,
Standard & Poor's Ratings Services, a division of The McGraw-Hill Companies,
Inc., had rated our senior unsecured debt at BBB-, its lowest investment grade
credit rating, and had placed that credit rating on creditwatch with negative
implications, and Fitch IBCA, Duff & Phelps had rated our senior unsecured debt
at BBB-. If one or more rating agencies downgrades our debt or trust preferred
securities, we may have difficulty obtaining financing and our cost of obtaining
additional financing or refinancing existing debt may be increased
significantly. A credit rating downgrade would cause the interest rate on our
$250.0 million short-term bank facility to increase by up to 3.5% and would most
likely require us to seek refinancing alternatives for the facility that would
not otherwise be required. In addition, credit rating downgrades to below BB+ or
Ba1 by Standard & Poor's or Moody's, respectively, would require us to increase
by 30% the quarterly redemption of the mandatorily redeemable cumulative

                                        6
<PAGE>

preferred securities of a subsidiary which owns a portion of our multi-client
library. If those credit ratings remain for a certain period of time or
deteriorate below BB- or Ba3, respectively, we must increase the quarterly
redemption of the preferred securities to an amount equal to 100% of the actual
revenue recognized from the licensing of the data held by that subsidiary. In
the event of a credit rating downgrade by both Standard & Poor's and Moody's, we
may be required to provide collateral or other credit support to one or more
lessors or other parties under UK leasing arrangements, which could adversely
affect our liquidity.

We are highly leveraged.

     As of December 31, 2001, we had approximately $2.8 billion of outstanding
debt, lease and preferred securities obligations. We estimate our total cash
obligations for these commitments to be $454.2 million, $723.1 million and $94.7
million for the years ended December 31, 2002, 2003 and 2004, respectively.

     Because of the level of our debt and other contractual cash obligations:

     - a substantial portion of our cash flow from operations must be dedicated
       to debt service and payments of such obligations and, to the extent so
       used, will not be available for operational purposes

     - our ability to obtain additional financing in the future may be limited
       and

     - our flexibility in reacting to changes in the operating environment and
       economic conditions, including possible future downturns in our business,
       may be limited

We are highly dependent on external sources of financing, improved cash flow and
proceeds from asset sales to meet our obligations and reduce our indebtedness in
the future.

     In the short-term, we expect a substantial portion of our liquidity to be
provided by our committed $430.0 million revolving credit facility and several
uncommitted bank lines. As of March 31, 2002, we had $70.0 million of borrowing
capacity under our committed revolving credit facility and approximately $40.0
million available under other uncommitted facilities. Additional borrowings
under our committed revolving credit facility are subject to a material adverse
change clause regarding our financial condition and to other conditions to
borrowing that are customary for such types of facilities. If either or both of
these sources of liquidity were not to be available, we would be substantially
dependent on operating cash flow, asset sales and external sources of financing
other than bank lines for our liquidity needs.

     In the longer term, our ability to pay debt service and other contractual
obligations will depend on improving our future performance and cash flow
generation, which in turn will be affected by prevailing economic and industry
conditions and financial, business and other factors, many of which are beyond
our control. If we have difficulty paying debt service or other contractual
obligations in the future, we will be forced to take actions such as reducing or
delaying capital expenditures, reducing costs, selling assets, refinancing or
restructuring our debt or other obligations and seeking additional equity
capital. We may not be able to take any of these actions on satisfactory terms
or at all.

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

     Our debt agreements contain restrictions and requirements relating to,
among other things:

     - the issuance of additional indebtedness

     - the maintenance of credit ratings

     - the maintenance of financial ratios

     - the encumbrance or sale of assets

     - the payment of dividends

     - capital expenditures

                                        7
<PAGE>

     - mergers

     - sale/leaseback transactions

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

RISK FACTORS RELATING TO OUR BUSINESS OPERATIONS

Our business could be adversely affected if low oil and gas prices decrease
demand for our services.

     Our business and operations depend upon exploration, development and
production spending by oil and gas companies. Low oil and gas prices, and
concerns about possible low oil and gas prices in the future, may reduce the
level of that spending. As overall conditions in the oil and gas industry
deteriorate, demand for our services and products may decrease and our business
may be adversely affected. Furthermore, recoveries in oil and gas prices do not
immediately increase exploration, development and production spending, so
improved demand for our services and products will generally lag oil and gas
price increases. In December 2000, we recognized impairment charges, including
multi-client library impairment charges, totaling $365.8 million, primarily due
to weakness in our geophysical services business. We also recognized $13.2
million in multi-client library impairment charges in 2001.

We could incur operating losses if we cannot keep our vessels and other
equipment utilized at high levels.

     Our businesses are capital intensive and generally require significant
investments in multi-client data, vessels and processing, seismic and other
equipment. As a result, we incur relatively high fixed costs in our operations.
If we cannot keep our vessels and other equipment utilized at high levels, we
could incur significant operating losses.

     In 2000 and 1999, we incurred net losses of $211.5 million and $33.8
million, respectively. In 2001, we had net income of $4.5 million on revenue of
$1.1 billion. We may incur losses in the future.

We invest significant amounts of money in acquiring and processing seismic data
for our data library without knowing 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

     - the value of our multi-client data could be adversely affected if any
       material adverse change occurred in the general prospects for oil and gas
       exploration, development and production activities in the areas where we
       acquire multi-client data

     Our future 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 adversely affect the value of the data.

     During 2001 and 2000, we recognized impairment charges of $13.2 million and
$166.5 million, respectively, against our multi-client library.

                                        8
<PAGE>

The amounts we amortize from our data library each period may fluctuate
significantly, and these fluctuations can have a significant effect on our
reported results of operations.

     How we account for our data library has a significant effect on our
reported results of operations. We amortize the cost of our multi-client data
library based in part on our estimates of future sales of data. These estimates:

     - are inherently imprecise

     - may vary from period to period depending upon market developments and our
       expectations

     - may result in periodic determinations of permanent value impairment

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

     In addition, our accounting policy requires that we reduce the book value
of our individual seismic surveys to a specified percentage of gross cost at the
end of each year regardless of sales. In December 2001 and 2000, we recognized
$39.1 million and $2.2 million, respectively, in such minimum amortization
charges. We recognize minimum amortization charges quarterly beginning in the
second quarter of each year, when we evaluate on a survey-by-survey basis the
minimum amortization requirements against the remaining sales estimates for that
year.

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:

     - the protection of the environment

     - exports and imports

     - occupational health and safety

     - permitting or licensing requirements for seismic activities and for oil
       and gas exploration, development and production activities

     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 be material in the future. Modification of existing laws or regulations or
adoption of new laws or regulations limiting exploration or production
activities by oil and gas companies or imposing more stringent restrictions on
seismic or hydrocarbon production-related operations could adversely affect us
by increasing our operating costs and/or reducing the demand for our services.

Our results of operations 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 commence production from floating production, storage and
       offloading vessels in a timely manner

     - failure to operate at high uptime performance levels on a sustained basis
       for technical reasons, including operational difficulties that require
       reworking of vessels

     - termination

     - redeployment of vessels following expiration or termination of long-term
       contracts

     - failure to produce expected amounts of oil and gas under contracts where
       our compensation depends on the amount of oil and gas produced
                                        9
<PAGE>

     Our FPSO vessel Ramform Banff is producing under contract at levels
substantially below its capacity and, as a result, is currently operating at a
loss.

     We have received notice of termination of the contract for the Varg field,
which is being produced by the FPSO vessel Petrojarl Varg.  The contract is
scheduled to terminate in July 2002. If and when we complete our acquisition of
the 70% interest in Production License 038, which includes the Varg field, we
expect to extend the terms of the contract on terms similar to the existing
terms. Please read "Information on the Company -- FPSO Operations -- Varg Field
Contract" in Item 4 of this annual report.

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 and is subject in varying degrees to risks inherent in
doing business abroad. These risks include:

     - war and terrorist activities

     - the possibility of unfavorable changes in tax or other laws

     - partial or total expropriation

     - restrictions on currency repatriation

     - 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

     - the disruption or delay of licensing or leasing activities

     - the requirements of partial local ownership of operations

We are subject both to hazards customary for marine operations and to those more
specific to our seismic and floating production, storage and offloading
operations.

     Substantially all of our operations are subject to perils that are
customary for marine operations, including capsizing, grounding, collision,
interruption and damage from severe weather conditions, fire, explosions and
environmental contamination from spillage. Any of these risks 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.

Because we do not have insurance to cover some operating risks, our results of
operations could be adversely affected if one or more of those risks occurred.

     We cannot always obtain full insurance for all of our operating risks. We
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. However, as a result of market conditions following the
events of September 11, 2001, premiums and deductibles for some of our insurance
policies are expected to increase substantially, and coverages may be decreased,
when we next seek to renew our coverages. For example, insurance carriers are
now requiring broad exclusions for losses due to war risk and terrorist acts. In
addition, some types of insurance coverage could become unavailable or available
only at very expensive premiums or for reduced amounts of coverage.

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. Although we
periodically undertake hedging activities in an

                                        10
<PAGE>

attempt to reduce certain currency fluctuation risks, these activities do not
provide complete protection from currency-related losses. In recent periods, we
have been required to recognize charges relating to the fair value of tax
equalization swap agreements due to changes in the exchange rate between the
Norwegian kroner and the United States dollar. Additionally, in some
circumstances our hedging activities can require us to make cash outlays.

OTHER RISK FACTORS

We could become liable for substantial taxes if we fail to qualify for the
Norwegian shipping tax regime.

     A significant portion of our operations are subject to the Norwegian
shipping tax regime and are therefore taxed at a zero rate. Qualification under
the Norwegian shipping tax regime is subject to special qualifications and
requirements, many of which are continuing and require strict compliance by us.
The Norwegian government could change or add to such qualifications and
requirements. If we fail to comply with the requirements of the regime or if we
are determined not to be entitled to the benefits under the regime, we could
become liable for substantial taxes, which could have a material adverse effect
on our financial position and results of operations.

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 many of our current
directors and executive officers do not reside in the United States. All or a
substantial portion of the assets of these persons and of PGS are/is 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 Norway in an original action based solely on
       United States federal securities laws

     - enforcing in Norway judgments obtained in the United States courts that
       are based upon the civil liability provisions of the United States
       federal securities laws

                                        11
<PAGE>

ITEM 4. INFORMATION ON THE COMPANY

OVERVIEW OF WHO WE ARE

     We are 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 executive offices
in both Lysaker, Norway (Strandveien 4, N-1366, 011-47-67-52-6600) and Houston,
Texas (16010 Barker's Point Lane, 77079, 281-589-7935, Attention: Chief
Financial Officer).

     We are a technologically focused oilfield service company. Our business
includes:

     - acquiring, processing and marketing seismic data. Oil and gas companies
       use the data to explore for new oil and gas reserves, to develop existing
       oil and gas reservoirs and to manage producing oil and gas fields.

     - providing floating production, storage and offloading, or FPSO, vessels.
       These vessels permit oil and gas companies to produce oil and gas from
       offshore fields and to process, store and offload the oil and gas for
       transport to refineries, distribution companies and end-users. We also
       provide various production management services related to these
       operations.

     - providing geophysical and other services that help oil and gas companies
       monitor producing oil and gas reservoirs to increase ultimate recoveries

BUSINESS STRATEGIES

     Our principal business strategies include:

     - using, developing and investing in advanced technologies for the
       acquisition, processing, interpretation and marketing of seismic data

     - increasing the returns from our geophysical business by using our
       advanced geophysical technologies and reservoir expertise and by
       increasing our current market share

     - increasing the returns from our production business by maintaining a high
       level of operational performance, actively pursuing various redeployment
       opportunities and using our geophysical knowledge and technology to
       maximize opportunities

     - using the capabilities of our Ramform seismic vessels to capitalize on
       market opportunities for high-definition seismic data

     - increasing our emphasis on the international seismic contract market

     - reducing costs and maximizing cash flow from operations

RECENT DEVELOPMENTS

  COMBINATION WITH VERITAS

     In November 2001, we entered into an agreement with Veritas DGC Inc., a
geophysical services company, to combine the businesses of the two companies
under a new Cayman Islands holding company, which we refer to as "Caymanco."
Under the agreement, Caymanco will make an exchange offer to issue its ordinary
shares in exchange for our outstanding shares and American Depositary Shares
representing our shares, or ADSs. Following the closing of the exchange offer,
Veritas will merge with a wholly owned

                                        12
<PAGE>

subsidiary of Caymanco. Upon closing of the exchange offer and the merger, PGS
and Veritas will become subsidiaries of Caymanco. The closing of the transaction
is subject to a number of conditions, including:

     - the tender in the exchange offer of PGS shares and ADSs representing more
       than 90% of the PGS shares outstanding as of the expiration of the
       exchange offer, which percentage may be reduced in limited circumstances
       described in the agreement

     - the approval of the merger by the stockholders of Veritas

     - the receipt of applicable regulatory clearances

     - PGS' having in effect definitive credit agreements or binding commitments
       providing for credit capacity of $430 million

     - Veritas' having in effect definitive credit agreements or binding
       commitments providing for credit capacity of $235 million

     - the authorization of the ordinary shares of Caymanco for listing on the
       New York Stock Exchange

     - PGS' having completed the previously announced sale of its Atlantis
       subsidiary

     - PGS' having entered into replacement employment agreements with some of
       its active employees

     - other customary conditions, including the absence of any events or series
       of events that has had or would have a material adverse effect on Veritas
       or PGS

     Under the agreement, a material adverse effect will be deemed to have
occurred and either party may terminate the agreement if, among other things:

     - the settlement price for the NYMEX natural gas futures contract for
       delivery 12 months following the month in which the relevant date of
       determination occurs falls below $2.25 per MMBtu for 20 consecutive
       trading days or

     - the settlement price for the NYMEX light sweet crude oil futures contract
       for delivery 12 months following the month in which the relevant date of
       determination occurs falls below $12.50 per barrel for 20 consecutive
       trading days

     A number of the conditions to the transaction have been satisfied,
including expiration of the applicable waiting periods under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, receipt of appropriate
clearance under UK competition law and our receipt of waivers under our $430
million credit facility sufficient to satisfy the related condition under the
agreement.

     We have had discussions with Veritas about amending the terms of the
agreement in various respects. Although no definitive amendment has been
reached, we expect any such amendment to include the following key terms:

     - our shareholders would receive 0.40 shares (previously 0.47 shares) of
       Caymanco for each of our shares or ADSs, and Veritas shareholders would
       receive one share of Caymanco for each Veritas share, resulting in
       Veritas shareholders owning approximately 44% of the Caymanco shares and
       our shareholders owning approximately 56% of the Caymanco shares upon
       completion of the transaction (assuming all our shares and ADSs are
       tendered and accepted in the exchange offer)

     - Veritas would be entitled to nominate six of the proposed ten directors
       of Caymanco while we would be entitled to nominate four directors

     - David B. Robson, the Chief Executive Officer of Veritas, would be the
       Chief Executive Officer of Caymanco and Reidar Michaelsen, our Chairman
       and Chief Executive Officer, would be the Chairman of the Board

     - Matthew D. Fitzgerald, the Chief Financial Officer of Veritas, would be
       the Chief Financial Officer of Caymanco

                                        13
<PAGE>

     - the transaction would be conditioned upon Veritas being treated as the
       acquiring company for accounting purposes

     In April 2002, Veritas reported that the SEC staff would not object to
Veritas being treated as the accounting acquiror. Any amendment to our agreement
with Veritas would be subject to final approval of the boards of directors of
each company.

     If we and Veritas amend the original agreement along the lines described
above and assuming all conditions precedent were satisfied or waived, we would
expect the transaction to close during the third quarter of 2002. However, we or
Veritas may not be able to satisfy all the conditions to closing, including the
sale of our Atlantis subsidiary, and there is no assurance that any conditions
that are not satisfied will be waived. In addition, the original agreement,
which is still in effect, provides that either party may terminate the agreement
if the transaction has not been effected by June 30, 2002. Accordingly, the
transaction may not close by the third quarter of 2002 or at all. Please read
"Key Information -- Risk Factors -- Risk Factor Relating to Our Pending
Transactions Involving Veritas DGC Inc. and Our Atlantis Subsidiary" in Item 3
of this annual report.

  SALE OF ATLANTIS

     In January 2002, we entered into an agreement with China National Chemicals
Import and Export Corporation, or "Sinochem," for the sale of our Atlantis
subsidiary. We expect proceeds from the sale to be approximately $200 million
plus certain qualifying capital expenditures incurred during 2002. Sinochem also
has agreed to assume $20.5 million of Atlantis' short-term debt. Consummation of
the sale is subject to a number of conditions, including the receipt of various
consents and waivers from governmental authorities and partners.

     In April 2002, we agreed with Sinochem to extend the period to close the
sale through June 28, 2002, although Sinochem has the right under the extension
to terminate the agreement after May 27, 2002. Under the extension agreement, if
the required closing conditions are satisfied or are waived by Sinochem after
May 20, 2002, then the sale proceeds will be reduced by $100,000 per day from
May 13, 2002 through the date that the closing conditions are so satisfied or
waived. If we terminate the agreement after June 28, 2002, we may be required to
pay a $1.4 million termination fee to Sinochem. If the sale is not consummated
and the agreement is terminated, we will continue to develop Atlantis' oil and
gas properties and may seek to dispose of Atlantis to either Sinochem under a
new agreement or to another buyer. We are continuing to pursue fulfillment of
the conditions to closing of the sale of our Atlantis subsidiary. However, as
several of the conditions are beyond our control, we may not be able to satisfy
all conditions, and the transaction may not close. Please read "Key
Information -- Risk Factors -- Risk Factor Relating to Our Pending Transactions
Involving Veritas DGC Inc. and Our Atlantis Subsidiary" in Item 3 of this annual
report.

SEISMIC BACKGROUND

  OVERVIEW

     Oil and gas companies use geophysical or seismic surveys to help them find
oil and gas and to determine the size and structure of known oil and gas
reservoirs. Seismic projects generally consist of planning a seismic survey and
acquiring, processing and interpreting seismic data. Such data are then used to
produce computer-generated graphic two-dimensional, or 2D, cross-sections or
three-dimensional, or 3D, images of the subsurface. Oil and gas companies use
these seismic images in evaluating whether to acquire new leases or licenses in
areas with potential accumulations of oil and gas, in selecting drilling
locations and in managing producing reservoirs.

     We refer to the repetition of identical 3D surveys over the same area at
different time intervals as 4D data or surveys. Oil and gas companies use these
surveys to gain an understanding of subsurface geophysical conditions that
change over time due to the depletion and production of the reservoir fluids.

                                        14
<PAGE>

  CONTRACT AND MULTI-CLIENT DATA

     We acquire seismic data both on an exclusive contract basis for our
customers and on our own behalf as multi-client data for licensing on a
non-exclusive basis to others. We acquire contract data for the specific client
that requests the data. We acquire and retain ownership of 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.

  DEMAND FOR SEISMIC DATA AND SERVICES

     Various factors influence the demand for seismic data and services,
including:

     - the demand for and prices of oil and gas and expectations about future
       prices

     - the level of exploration and production spending by oil and gas companies

     - developments in technology that affect the cost, quality and reliability
       of seismic data

  WHERE WE ACQUIRE SEISMIC DATA

     We conduct the majority of our seismic data acquisition business in the
North Sea and offshore Brazil and West Africa. We also acquire seismic data in
other active oil and gas exploration and/or production areas around the world
from time to time, including:

     - the Gulf of Mexico

     - offshore China and Korea

     - offshore and onshore India and Pakistan

     - the Sakhalin area of Russia

     - offshore Australia, Indonesia and other countries in the Asia Pacific
       region

     - offshore Canada

     - offshore and onshore in the Middle East

     - the Caspian Sea area

     - offshore and onshore Mexico and Latin America

     - the US mid-continent, Rocky Mountain and Alaskan North Slope regions

  HOW WE ACQUIRE SEISMIC DATA

     To acquire marine seismic data through conventional streamer operations, we
discharge a wave of acoustic energy just below the water's surface from one or
more energy sources towed behind one or more survey vessels. As the wave travels
through the water and subsurface earth, portions of the wave are reflected back
at rock layer boundaries. The reflections are detected by hydrophones contained
in streamers towed behind the survey vessels. The streamers convert the
reflected waves into digital data that are then transmitted to a recording unit
onboard the survey vessel. We then analyze the acquired data for quality control
purposes before inputting the data into a processing system to produce images of
the subsurface. In addition to conventional streamer operations, we also acquire
marine seismic data through seafloor seismic operations in which we place
recording cables on the ocean floor and retrieve them as data are acquired.

     A 2D marine seismic survey typically is produced by a single survey vessel
towing a single streamer and one energy source. The seismic data acquired
generally represent a vertical cross-section beneath the line tracked by the
streamer, which we refer to as a "seismic line." We acquire 3D data by combining
parallel 2D seismic lines that can be processed to produce a three-dimensional
image of subsurface strata. When we perform a 3D seismic survey, we acquire a
dense grid of seismic data using multiple streamer
                                        15
<PAGE>

configurations over a precisely defined area. Such data acquisition requires the
use of sophisticated navigation equipment that permits the constant and precise
determination of the positions of streamers and energy sources during the
acquisition process. This determination of position is essential to producing
accurate subsurface images. When we perform a 4D seismic survey, we repeat a
series of 3D seismic surveys over the same survey area at different time
intervals. This series of surveys shows the changing subsurface geophysical
conditions over time and provides information about the fluid movements in the
area.

     In acquiring 3D marine seismic data, we may use multiple vessels and
multiple streamers and energy sources to acquire more rapidly, and at lower unit
cost, the large number of seismic lines needed to produce a 3D data volume. By
increasing the number of streamers and energy sources used, we can perform large
surveys more rapidly and cost-effectively. Dual vessel operations, with one
vessel acting as a source/recording vessel and the other as a recording vessel,
permit us to acquire data in areas where production platforms or other
obstructions interfere with seismic operations. Dual vessel operations also
generally allow us to use shorter streamers, which improves efficiency and
reduces the chance of collision or entanglement with obstructions. In addition,
we use multiple vessel and streamer configuration operations to acquire data for
imaging deep targets.

     To image complex geophysical and geological areas more accurately, we
deploy a dense configuration of streamers using a single energy source to
enhance seismic data quality and resolution. This technology is known as
HD3D(TM) seismic technology, and has become cost effective due to the
utilization of vessels, like our Ramform seismic vessels, that have the
capability to tow in excess of 12 streamers at a time. We believe that useful 4D
seismic information requires HD3D(TM) or similar seismic technology and
increased computing capacity to reflect the subtle changes in geophysical
conditions that occur over time. We believe that oil and gas companies find 4D
seismic surveys and related reservoir monitoring services to be particularly
useful in their efforts to increase recoveries from producing petroleum
reservoirs. Please read "-- Reservoir Monitoring."

     To acquire land seismic data, we use an explosive or mechanical vibrating
unit to produce an acoustical impulse that is reflected back at rock layer
boundaries. A recording unit synchronizes the shooting and captures the
reflected signals via geophones placed on or planted in the ground that produce
an electrical current when the ground moves. On a typical land survey, several
thousand geophones are laid out in multiple lines to record the acoustical
impulse. The data are then processed to produce a 3D image that enables
geoscientists to visualize prospective drilling areas and producing oil and gas
reservoirs.

FPSO BACKGROUND

  OVERVIEW

     In the remainder of this annual report, we will use the acronym "FPSO" to
refer to floating production, storage and offloading.

     An FPSO system is a type of mobile production unit that produces,
processes, stores and offloads oil and 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 an overall technical and
financial evaluation of the field to be developed. FPSO systems typically
perform the same function as fixed offshore platforms in the offshore production
of oil and gas, with the exceptions of drilling and heavy well maintenance.
However, FPSO systems provide a number of advantages over fixed platforms
including:

     - 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

     - reducing the time from the discovery of oil and gas to production

                                        16
<PAGE>

     An FPSO vessel may be either a newly constructed vessel specifically
designed to function in an FPSO system or an existing tanker or other marine
vessel converted to function in an FPSO system. A typical FPSO life-of-field
system consists of wells completed using subsea wellheads that are connected to
the FPSO vessel by flexible tubing, or risers. Risers carry the oil and gas from
the ocean floor to the vessel. The oil and gas are processed onboard the FPSO
vessel and the resulting oil is exported, either by a subsea pipeline or an
off-take system using shuttle tankers. Natural gas may be exported by subsea
pipeline, reinjected into the reservoir or, in some circumstances, flared.

  DEMAND FOR FPSO SERVICES

     How the FPSO Market Differs from the Seismic Market. The market for FPSO
services differs fundamentally from the seismic market. Offshore production,
either for test purposes or for full exploitation, generally takes place a
relatively long time after exploration drilling has been completed. Oil and gas
companies typically make production-related decisions based on different
financial parameters and with different views about changes in oil and gas
prices than are used for decisions relating to seismic or drilling activities.
Oil and 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 gas companies
must reduce cost levels and financial exposure. As a result, producers have
focused increasingly on subsea installations and FPSO systems instead of the
more traditional fixed steel and concrete platforms.

     The FPSO Market. The market for FPSO systems can generally be divided into
three segments:

     - extended well tests or production testing

     - early production

     - life-of-field development

     In production testing, the oil and gas company produces oil and gas from
one or more producing formations or zones, and from one or more wells, to
confirm various characteristics of a reservoir. The oil and gas company then
uses this information, among other things, to make better estimates of the
productivity and extent of the reservoir and to position production facilities.
From the perspective of an FPSO operator, use of FPSO systems for production
testing, which is relatively short-term in nature, involves a greater risk that
the FPSO system will not maintain high utilization rates due to downtime between
contracts.

     The early production phase of development follows the decision to develop a
tested field into full production. During this phase, production facilities are
engineered, built and installed. By increasing production during this phase, the
overall financial performance of the field can be enhanced by reducing the need
for or level of financing and by providing income and cash flow at an earlier
stage than would otherwise be the case.

     In life-of-field development, the FPSO system is designed for production
for the life of the field and the operator generally attempts to adapt either
the production facility to the reservoir requirements or the reservoir strategy
to the production facility.

                                        17
<PAGE>

PROPERTY, PLANT AND EQUIPMENT INFORMATION

     We incorporate by reference in response to this item the information in
"Operating and Financial Review and Prospects -- Financial Condition -- Capital
Requirements" in Item 5 and note 20 of the notes to our 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.

  LEASED PREMISES

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

  OUR SEISMIC VESSEL FLEET AND CREWS

     We believe that we operate one of the most advanced marine seismic data
acquisition fleets in the world. To improve crew productivity and efficiency, we
emphasize a high ratio of streamers towed to vessels in operation. As of
December 31, 2001, we had a total of ten 3D marine seismic streamer crews
operating 17 seismic vessels, and one 2D marine seismic streamer crew operating
one seismic vessel. In addition, as of December 31, 2001, we had two seafloor
seismic crews operating a total of nine vessels. Our seafloor seismic crews
perform our ocean bottom seismic operations, as well as other forms of multi-
component operations.

     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 full 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.

     Equipment Used on Our Seismic Vessels. Most of our seismic vessels, other
than those used in seafloor seismic operations, have an equipment complement
consisting of the following:

     - recording instrumentation

     - digital recording streamers

     - streamer and seismic data location systems

     - supercomputer systems for data processing

     - multiple navigation systems

     - except for vessels that record only, a source control system that
       controls the synchronization of the energy sources and a firing system
       that generates acoustic energy

     For seafloor seismic operations, the Ocean Explorer, the Carlson Tide, the
Bergen Surveyor, the Jonathan Chouest and the Dickerson Tide each have 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.

                                        18
<PAGE>

     Vessel Information. We provide in the following table information as of
December 31, 2001 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       2001)       EXPIRATION
-----------                       -------------   ------   ------   ------------   ------------   ----------
<S>                               <C>             <C>      <C>      <C>            <C>            <C>
3D SEISMIC VESSELS:
Ramform Challenger..............  1996            284      130           16             12           Owned
Ramform Explorer................  1995            270      130           12              8           Owned
Ramform Valiant.................  1998            284      130           20             10         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(2)..............  1995/96         246       49            4              4            2004
Geo Explorer(2)(3)..............  1991            215       46            3              3            2002
Walther Hervig(2)(3)(4).........  1997            254       56            5              4            2002
Falcon Explorer(2)..............  1997            266       53            1              1            2002
SEAFLOOR SEISMIC VESSELS(2):
Carlson Tide....................  1995            194       40          N/A            N/A            2002
Dickerson Tide..................  1995            194       40          N/A            N/A            2002
Beulah Chouest..................  1996            195       40          N/A            N/A            2002
Jonathan Chouest................  1996            180       34          N/A            N/A            2002
Kondor Explorer(2)..............  1997            197       43          N/A            N/A            2002
Bergen Surveyor.................  1997            217       48          N/A            N/A            2004
Ocean Explorer..................  1993/95         269       59            6              6           Owned
</Table>

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

(1) We have UK lease arrangements for each of the Ramform Valiant, the Ramform
    Viking, the Ramform Victory and the Ramform Vanguard. Under the leases, we
    lease the vessels from UK financial institutions 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. We used a substantial portion of the
    proceeds from these arrangements to legally defease the present value of our
    future charter obligations for the vessels.

(2) These vessels operate in a multi-vessel configuration.

(3) Chartered from a limited partnership owned 50% by us.

(4) Currently stacked and not operating.

     Several of our 3D seismic vessels and substantially all of our seafloor
seismic vessels operate under charter agreements expiring in 2002. These charter
agreements typically are renewed on an annual or other relatively short-term
basis. We believe that maintaining a number of short-term vessel charters
provides more flexibility to adjust the size of our fleet according to market
demands.

  OUR RAMFORM SEISMIC VESSELS

     As of December 31, 2001, we operated six Ramform design vessels in our
marine seismic data acquisition operations. Each of the Ramform seismic vessels
is a state-of-the-art vessel that is capable of pulling a relatively large
number of streamers and is built according to a design in which we own
proprietary rights. Our four Ramform seismic vessels delivered in 1998 and 1999
are designed to deploy up to 20 streamers.

     We believe that our Ramform design seismic vessels represent the most
advanced seismic vessels currently in operation in the world. Because of their
size and unique design, including their extreme width
                                        19
<PAGE>

in relation to their overall length, Ramform design seismic vessels have an
increased streamer towing capacity as compared to conventional seismic vessels.
In addition, the Ramform vessels have increased stability and improved motion
characteristics over conventional seismic vessels. Among other things, these
characteristics allow these vessels to leave seismic equipment deployed during
more severe weather conditions than is possible for conventional seismic
vessels. As a result, these vessels can resume production more quickly once
conditions have stabilized and thereby acquire seismic data for more sustained
periods of time. The size and unique design of the Ramform seismic vessels,
together with our advanced techniques for rapid deployment and retrieval of
seismic streamers, allow us to acquire marine seismic data more efficiently. The
Ramform design seismic vessels are also well-suited for acquiring high-
definition surveys, which require the use of multiple streamer configurations
with narrower distances between streamers in order to generate the necessary
density of seismic data for enhanced resolution. The Ramform design seismic
vessel has recently completed seismic surveys using HD3D(TM) seismic technology.
We have experienced an increase in demand for data acquired in this manner.

  FPSO VESSELS

     As of December 31, 2001, we owned and operated four FPSO systems and
provided operations and maintenance services, on a contract basis, to 17
additional offshore production facilities for oil and gas companies.

     We provide in the following table information as of December 31, 2001 about
our owned FPSO vessels(1).

<Table>
<Caption>
                                    APPROXIMATE   APPROXIMATE   PRODUCTION   2001 AVERAGE
                                       TOTAL         TOTAL       CAPACITY     PRODUCTION    DISPLACEMENT    STORAGE
                          YEAR        LENGTH         WIDTH       (BARRELS    (BARRELS PER     (METRIC      CAPACITY
FPSO VESSEL NAME        DELIVERED     (FEET)        (FEET)       PER DAY)      DAY)(3)         TONS)       (BARRELS)
----------------        ---------   -----------   -----------   ----------   ------------   ------------   ---------
<S>                     <C>         <C>           <C>           <C>          <C>            <C>            <C>
Ramform Banff(2)......    1998          395           175         95,000        22,700         32,100       120,000
Petrojarl I...........    1986          686           105         50,000        37,300         51,000       190,000
Petrojarl Foinaven....    1996          820           112        180,000        81,300         72,000       280,000
Petrojarl Varg........    1999          702           125         56,000        20,300        100,000       420,000
</Table>

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

(1) Additionally, in our FPSO operations we utilize six FPSO shuttle
    tanker/storage tanker vessels from third-party contractors under operating
    leases (some of which are in turn subleased) expiring at various dates from
    2003 through 2004.

(2) We have a UK lease arrangement for the vessel's topside production
    equipment. Under the lease, we lease the equipment from a UK financial
    institution under a long-term charter that gives us the option to purchase
    the equipment for a de minimis amount at the end of the charter period. We
    used a substantial portion of the proceeds from the arrangement to legally
    defease the present value of our future charter obligations for the
    equipment.

(3) Average production is computed by dividing total production by the number of
    days of operation of the relevant vessel.

  ESTIMATED FUTURE CAPITAL EXPENDITURES

     We do not have any material commitments for future capital expenditures.
However, during 2002 we expect to spend approximately $45.0 million on upgrades
of our geophysical assets and $15.0 million on our production assets
(approximately $10.0 million of which represents the final payment on the
Petrojarl I upgrade). We anticipate that we will spend additional capital on
Atlantis-related development costs, which costs will be terminated if we are
successful in selling Atlantis. We expect that a substantial portion of the
Atlantis-related capital expenditures that we incur will be reimbursed if and
when the sale of Atlantis closes. Please read "-- Recent Developments -- Sale of
Atlantis."

                                        20
<PAGE>

SEISMIC DATA ACQUISITION

  CONTRACT OPERATIONS

     Overview. When we acquire seismic data on a contract basis, our customer
directs the scope and extent of the survey and retains ownership of the data
obtained. Contracts for seismic data acquisition, which are generally awarded on
a competitive bid basis, typically are turnkey contracts. Under this turnkey
method, our customers pay us based upon the number of seismic lines or
kilometers of seismic data collected and bear most of the risk of business
interruption, except in winter months when we assume greater responsibility for
weather-related interruption. We generally require progress payments unless we
expect to complete the survey in a brief period of time.

     Geographic Mix of Operations. We expect in the near term to focus on
contract revenue in the North Sea, in the Asia Pacific and Middle East regions
and offshore West Africa and South America. However, we also intend to seek
opportunities for contract revenue in other areas of the world where offshore
oil and natural gas operations exist. During 2001, we performed or secured
contract work in the North Sea; Mexico; offshore West Africa, Australia, China
and other countries in the Asia Pacific region; offshore and onshore Canada; the
US mid-continent, Rocky Mountain and Alaskan North Slope regions and the Middle
East region. For more information regarding the geographic mix of our operations
for the last three fiscal years, please read note 20 of the notes to our
financial statements in Item 18 of this annual report.

  MULTI-CLIENT OPERATIONS

     Overview. We continue to build and market our seismic data library,
including seafloor seismic data, with a particular emphasis in the North Sea,
offshore Brazil and West Africa and in the Gulf of Mexico. We expect to continue
this geographic focus in the future, but also intend to acquire multi-client
seismic data in additional geographic areas from time to time, including
offshore Australia and other countries in the Asia Pacific region and in the US
mid-continent and Rocky Mountain regions.

     From the perspective of an oil and gas company, purchasing multi-client
seismic data is less expensive on a per unit basis than contracting to have
seismic data acquired on an exclusive basis. From our perspective, multi-client
seismic data are 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 may be more profitable than contract data, but 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. We reduce this risk by
obtaining prefunding for a portion of such costs. The level of prefunding
obtained for each multi-client seismic survey is determined, in part, 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 gas to
       market

     - the historical turnover of the leased acreage

     - the level of interest from oil and gas companies in the area

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

     Geographic Areas Covered by Multi-Client Seismic Data. A substantial
portion of our Gulf of Mexico marine seismic data library has been acquired
offshore Louisiana and Texas, including deepwater areas. We have also acquired
significant data in the deepwater areas in the North Sea and offshore Brazil and
West Africa. We believe that the deepwater areas in the Gulf of Mexico, the
North Sea and offshore

                                        21
<PAGE>

Brazil and West Africa will be among the most active offshore exploration and
development areas in the near future. We also believe that the relatively high
cost of locating and producing deepwater oil and gas reservoirs will contribute
to increased demand for high density marine seismic data and other specialized
geophysical services which allow oil and gas companies to better define oil and
gas reservoir potential. For more information regarding the geographic mix of
our operations for the last three fiscal years, please read note 20 of the notes
to our financial statements in Item 18 of this annual report.

     Marketing Arrangements. We market multi-client data through our own
organization and through various arrangements with third parties. Under
arrangements relating to some of our multi-client seismic data programs in the
Gulf of Mexico, we work with a third-party marketing company that presents to us
seismic survey projects for our consideration. We acquire and process, or have a
designee process, the data for the surveys that we choose to undertake. We then
retain ownership of the data acquired, with the marketing company earning a
commission or other compensation on the data it sells. We may grant an ownership
interest in the data to the marketing company under a risk-sharing arrangement
in limited circumstances.

  SEAFLOOR SEISMIC OPERATIONS

     As of December 31, 2001, we had two seafloor seismic crews. One crew was
outfitted with conventional ocean bottom cable technology, capable of recording
multi-component seismic data in relatively shallow water. The second crew was
outfitted with our proprietary FOURcE(TM) seafloor seismic acquisition
technology, capable of recording multi-component seismic data in deeper water
depths.

     Seafloor seismic acquisition is used 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.

     In multi-component seafloor seismic operations, both hydrophone and
three-component geophone data are recorded simultaneously for a reservoir.
Processing the data with our 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 maximizing total
       reserve recovery at the production stage

  LAND OPERATIONS

     As of December 31, 2001, we had eight 3D land seismic acquisition crews
operating in various areas, including Mexico, the Middle East and the US
mid-continent, Rocky Mountain and Alaskan North Slope regions. We are also
developing a multi-client data library of gas basins in the United States.

     We believe that our land seismic acquisition business offers the technical,
and administrative support for successful growth into new land markets. We are
able to field well-equipped crews on a timely basis through established volume
purchase agreements that provide us with technologically-advanced recording,
positioning, drilling and camp equipment.

SEISMIC DATA PROCESSING OPERATIONS

     We provide seismic data processing services for our own seismic data
acquisition operations and for third parties. We generally compete for data
processing contracts on a competitive bid basis. These contracts generally
provide for the customer to pay a flat fee per mile or kilometer processed for a
prescribed set of processing procedures. Additional procedures may be quoted
separately and are frequently added during the course of the project.
                                        22
<PAGE>

     We operate four land-based seismic data processing centers, located in
Houston, Texas, USA.; Cairo, Egypt; London, England; and Perth, Australia. Each
of these centers is equipped with supercomputers for data processing. We also
have a processing center in Oslo, Norway that is linked to our other centers'
supercomputers. We use a proprietary operating system for our supercomputers,
which is designed to take advantage of supercomputer architecture and can be
converted to operate on a variety of supercomputers. These supercomputers offer
processing capacities for the large data volumes and computer-intensive
algorithms requiring numerous simultaneous calculations that are inherent in
seismic data processing. Through our seismic data processing operations we
provide:

     - 3D data processing of land and marine seismic surveys

     - onboard (vessel) seismic data processing for reduced delivery times and
       enhanced real-time quality control for data

     - multi-component and 4D seismic data processing for reservoir
       characterization and monitoring

     - imaging of subsurface structures in deepwater and under salt formations

     We have deployed the onboard supercomputer processing systems for most of
our marine seismic data acquisition crews and have stationed processing
personnel onboard these vessels to process and provide quality control of the
seismic data as they are acquired. We believe that onboard processing and
quality control provide a competitive advantage because we can process the large
volume of data associated with seismic surveys concurrently with data
acquisition. This concurrent process allows us to shorten the period of time
required to deliver high-quality finished data to the customer. In addition,
onboard processing and quality control allow us to decide whether we should
resurvey particular areas to fill gaps in the original data while the vessel and
crew are on the prospect areas. As a result, we can resurvey more quickly and
less expensively.

RESERVOIR MONITORING

     We believe that the high-resolution 4D seismic data used in connection with
reservoir monitoring will help oil and gas companies maximize production and
increase the ultimate recoveries from producing hydrocarbon reservoirs,
particularly as the level of production from such reservoirs begins to decline.
In addition to the equipment and technology required for a 3D seismic survey, a
4D seismic survey may require or use:

     - streamer technology

     - vertical cable technology

     - dual sensor or multi-component seafloor technology

     - permanent installations of seismic receivers

     4D seismic information requires a higher density of 3D data and increased
computing capacity to reflect the subtle changes in geophysical conditions that
occur over time. With our advanced vessel fleet, the large streamer capacity of
our Ramform design seismic vessels, our expertise in acquiring, processing and
interpreting 4D seismic data and our processing capacity, we believe that we are
well positioned to meet future demand for 4D seismic surveys.

DATA MANAGEMENT

     In March 2001, we sold our global Petrobank data management business and
related software for $165.7 million in net cash to Landmark Graphics
Corporation, a Halliburton Company subsidiary. We also entered into an agreement
with Landmark to provide data management and distribution services to us. This
agreement has an initial term of three years, but may be extended on similar
terms by mutual agreement of the parties for up to two additional one-year
periods. During the term of the agreement, Landmark will be our exclusive
provider of data storage and distribution services, except where otherwise
                                        23
<PAGE>

agreed. The cost of these services for the ten month period ended December 31,
2001 was $8.0 million. The financial position and results of operations of our
Petrobank data management business were not material to our consolidated
financial position and results of operations for any year presented in this
annual report.

FPSO OPERATIONS

     We believe that our advanced geophysical technologies and reservoir
expertise allow our FPSO customers to increase the amounts of oil and gas
produced from the reservoirs served by our FPSO systems and assist in the
identification of satellite fields that can be economically produced or "tied
back" through the same systems. We believe that we can increase our revenue and
operating profit from any incremental production through our FPSO systems
through the use of contracts with a variable compensation component based on the
amount of oil produced. As a result of these factors, we believe that we have a
competitive advantage over other FPSO operators.

     As of December 31, 2001, we owned and operated four FPSO systems, the
Ramform Banff, the Petrojarl Foinaven, the Petrojarl Varg and the Petrojarl I.
The contracts under which these FPSO systems operated are described below.

  BANFF FIELD CONTRACT

     In February 1997, Conoco awarded us a long-term contract to provide an FPSO
system, the Ramform Banff, to produce the hydrocarbon reserves of the Banff
field in the UK sector of the North Sea. Oil production from the field commenced
in late 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.

     If actual production averages less than 8,000 barrels per day for a period
of 90 days, and continues to average less than that volume for at least two
years after the commencement of the initial 90-day period, Conoco has the right
to terminate the contract at the end of those two years. Conoco also may
terminate the contract without paying a cancellation fee with twelve months
written notice or if:

     - the Ramform Banff becomes a total loss

     - there is a breach of the FPSO contract by us that is not remedied within
       agreed deadlines

     - we enter into debt negotiations with creditors or go into liquidation or
       are placed under administration

     - force majeure events occur that are expected to continue for more than
       six months

     During the fourth quarter of 2000, the Ramform Banff discontinued
production on the Banff field and demobilized to Germany, where an upgrade to
reduce vessel roll motion and improve uptime performance commenced. The upgrade
was completed during the first quarter of 2001, and production on the Banff
field recommenced in March 2001. From that time, the Ramform Banff operated with
greater than 99% uptime performance over the remainder of the year.

     The financial performance of the vessel continues to suffer due to
relatively low levels of production resulting from underperformance of the
reservoir itself. Additionally, the operating costs of the Ramform Banff are
higher than originally expected. We have hired a storage vessel at a rate of
$47,000 per day under a long-term charter arrangement relating to the operations
of the Ramform Banff. Because of the higher than expected cost of operating the
field, the additional cost associated with the storage tanker and the low level
of oil production from the field, we have incurred losses on the contract. For
additional information relating to the financial performance of the Ramform
Banff, please read "Operating and Financial Review and Prospects -- Results of
Operations -- Fiscal 2001 Compared with Fiscal 2000" and "Outlook; Factors
Affecting Our Future Operating Results" in Item 5 of this annual report.

     While we believe that Conoco has plans to drill one or two new wells during
the second half of 2002 to increase field production, we cannot estimate the
incremental production that might be provided by

                                        24
<PAGE>

such additional wells, if any. Therefore, we cannot reasonably estimate whether
losses will continue and, if so, at what level.

     Based on a longer term assessment, we believe that the Ramform Banff should
be removed from the Banff field and deployed on a field better suited for its
production capacity. As a result, we are evaluating an alternative production
solution for the Banff field and actively seeking to redeploy the vessel
elsewhere.

     If we succeed in obtaining a new contract for the Ramform Banff, it is
possible that additional capital may be needed to prepare the vessel for the new
contract. Additionally, we have invested $64.6 million in subsea equipment on
the Banff field as of December 31, 2001, and a premature exit from the field
could result in an impairment of the equipment unless the owners of the field
pay a value equal to or greater than its book value at the time of exit.

  FOINAVEN FIELD CONTRACT

     The Petrojarl Foinaven is under contract with Britoil PLC, a subsidiary of
BP Amoco Plc, for production of the Foinaven field to the west of the Shetlands.
Commercial production on the field commenced in November 1997. The Foinaven
contract is not limited as to time. Britoil may terminate the contract in
November 2002 or later, with a minimum of two years' notice. We have not
received any notice of termination from Britoil, and we currently expect that
the vessel will remain on the field for a substantial period. In the event of
cancellation at the end of the fifth anniversary, the contract provides that
Britoil must pay a cancellation fee of $60 million, which fee reduces by $12
million per year so that no cancellation fee is payable after November 2007.
Britoil may also terminate the contract without paying a cancellation fee if,
among other things:

     - the Petrojarl Foinaven becomes a total loss

     - there is a breach of the FPSO contracts by the FPSO contractor that is
       not remedied within agreed deadlines

     - the FPSO contractor or its guarantors enter into debt negotiations with
       creditors or go into liquidation, are placed under administration or
       change ownership to the detriment of Britoil

     - force majeure events occur that are expected to continue for more than
       365 days

     In addition, the contract may be terminated:

     - by us with a minimum of two years' notice, if the production-dependent
       tariff falls to less than the equivalent of $102,250 per day

     - from November 26, 2003 with one year's notice if the production-dependent
       tariff falls below $35,000 per day

     - under additional circumstances, including war

     The contract provides for compensation consisting of a fixed day rate and a
production-dependent tariff. The current day rate is approximately $66,000 per
day and is subject to adjustment according to agreed indices. The
production-dependent tariff:

     - is not subject to adjustment based on any index

     - is equal to $3.50 per barrel for the first 25,000 barrels of production
       per day and $2.95 per barrel for production in excess of 25,000 barrels
       per day

     - may depend upon a guaranteed minimum production volume equal to 95% of
       the predetermined production profile during the first five years of the
       contract

As long as the Petrojarl Foinaven is fully operational, Britoil will be
required, in periods during the first five-year period where the actual
production falls below the guaranteed minimum production, to make

                                        25
<PAGE>

payments based on the guaranteed minimum production less credits for rate
payments already made for volumes in excess of the guaranteed minimum
production. If actual production is greater than the guaranteed minimum
production in periods during the first five-year period, Britoil will make
payments based on actual production less credits for rate payments already made
for volumes below the guaranteed minimum production. During periods after the
first five-year period in which the Petrojarl Foinaven is fully operational, the
day rate will be approximately $66,000 per day, subject to adjustment according
to agreed indices, and the production-dependent tariff will be based on the
greatest of:

     - actual production

     - 90% of the highest of two expected annual oil production rates reported
       by Britoil and the planned production profile for the year in question or

     - 10,000 barrels per day

     The guaranteed minimum production amounts under the contract was 80,750
barrels per day in year 4, which ended in November 2001, and is 70,775 barrels
per day in year 5. In periods when the Petrojarl Foinaven is not fully
operational, the day rate payable is to be based on actual production. A
reduction in production volume during the first five years that is due to
matters for which we are responsible triggers a day rate equal to $60,000, as
adjusted to reflect indexation, plus an additional $52,500 until production is
resumed. After five years, the day rate under such circumstances will be
$66,000, as adjusted to reflect indexation.

     In periods of production stoppage covered by the contract's repair and
start-up quota, we will be entitled to receive the day rate. We can accumulate
credits under the quota at a rate of 24 hours per month, up to an annual maximum
of 14 days, to be offset by any downtime taken. In periods when production is
prevented or reduced due to force majeure, we will receive reduced income for 60
days, and the full production rate thereafter.

     Britoil has the right to add production from a satellite field, the
Foinaven East field, to the contract and exercised that right during the 2001
fourth quarter. To the extent that production from the Foinaven East field, when
aggregated with Foinaven field production, is within the guaranteed minimum
production level, the normal rate structure under the contract will apply.
Foinaven East production in excess of the guaranteed minimum production amount
will be paid at an incremental rate of at least $0.75 per barrel. We are
currently receiving $0.75 per barrel of oil produced from the Foinaven East
field. From commencement of production in the fourth quarter of 2001 through
April 2002, Foinaven East production has averaged 8,800 barrels per day.

     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 breaches of
       contract due to deficiencies that provide Britoil a right to terminate
       the production contract

     - contribute up to 80% of the payments expected to be made by Britoil under
       the contract for the year following the discovery of hidden defects
       toward the correction of those defects, where such correction involves
       extraordinary expense

     - pay for pollution damage caused by diesel or lubricants used on the
       Petrojarl Foinaven during production

  VARG FIELD CONTRACT

     We charter the Petrojarl Varg to Saga Petroleum ASA, with Saga acting on
behalf of the owners of the production license relating to the Varg field
offshore Norway. We operate the vessel on behalf of the

                                        26
<PAGE>

license owners. The Petrojarl Varg currently operates in the Varg field, where
production began in December 1998. The charter agreement provides for:

     - a lease term for at least the full productive life of the Varg field,
       with a minimum term through July 22, 2002, subject to termination by the
       license owners either with or without cause. If termination is without
       cause, we are entitled to receive the applicable charter hire rate
       indicated below for the minimum term.

     - a day rate of:

      - $177,000 through July 22, 2002

      - $162,000 after that date

The owners of the production license may terminate the contract for cause if:

     - there is a substantial breach of the FPSO contract by us

     - we become insolvent, make an arrangement with our creditors or otherwise
       become incapable of performing the required services under the contract

     - force majeure events occur that continue or are expected to continue for
       more than 90 days

In addition, the contract will terminate if the Petrojarl Varg becomes a total
loss.

     The operating agreement provides:

     - that we will perform various operating services for the license owners
       relating to the Petrojarl Varg and be compensated for those services in
       NOK at a day rate of approximately NOK 360,000, subject to escalation
       based on various price indices

     - for a minimum term through July 22, 2002, subject to termination by the
       license owners either for breaches by us or without cause. If termination
       is without cause, we are entitled to receive the applicable contractual
       compensation, less savings we realize from not being obligated to perform
       the agreement

     On April 29, 2002, we received notice of termination from the license
owners, and the charter and operating agreements will terminate in late July
2002. However, if we complete our purchase of the 70% interest in the license
described below, we intend to extend the charter and operating agreements on
terms similar to the existing terms.

     During the 2002 first quarter, we entered into agreements to purchase a 70%
interest in Production License (PL) 038 on the Norwegian Continental Shelf of
the North Sea. PL 038 includes the Varg license. If we consummate the purchase,
the interests in PL 038 will be purchased from Statoil (which holds a 28%
interest) and Norsk Hydro (which holds a 42% interest). As consideration for our
70% interest, we will assume a portion of the abandonment liabilities associated
with the fields on the license and any future environmental liabilities that may
be generated by production on the fields. We estimate these abandonment
liabilities to range up to $32.0 million in gross costs, or $12.0 million in
after-tax costs. The purchases are contingent on the approval of Norwegian
authorities and expected to close during the 2002 third quarter. Upon completion
of the purchases, our 30% partner will be the Norwegian government's State
Direct Financial Interest. We intend to continue operating on the field once the
purchase is complete. 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.

  GLITNE FIELD CONTRACT

     In September 2000, we entered into an agreement with 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 the 2001 third quarter. Production under the
contract is expected to last between 26 and 30 months from the production
commencement date, with the first 18 months of production effectively guaranteed
by Statoil.

                                        27
<PAGE>

     The contract provides for the following compensation structure (subject to
annual adjustment according to agreed indices):

     - a day rate of $121,250 plus a per barrel tariff for a period of 36 months
       from commencement of commercial production. The basic per barrel tariff,
       which is based on a contractual production profile, escalates from $0.50
       per barrel for the first 12 months of production, to $0.70 per barrel for
       the following 12 months of production, to $1.50 per barrel for the
       following 12 months of production. For production in excess of the
       contractual production profile, the tariff rates are $3.50 per barrel,
       $3.30 per barrel and $2.50 per barrel for the respective 12 month
       periods.

     - a maximum compensation of $145,000 per day from the 19th month of
       production through the 36th month of production (inclusive of tariff
       elements)

     - a flat day rate of $127,500 beginning 36 months after the commencement of
       commercial production

     - an additional $12,750 per day (to the $127,500 flat rate) from the 36th
       month of production through the 60th month of production

     - an additional $6,200 per day (to the $127,500 flat rate) from the 60th
       month of production through the 120th month of production

     Under certain force majeure and standby situations, we will receive a day
rate generally equal to $85,000. If production is shut down for a period
cumulatively exceeding 144 hours during any six-month period, except for any
period where such production shut down has been caused by Statoil, there will be
no compensation. The first six-month measurement period began on August 28,
2001, the date of commencement of commercial production. We have the right to
accumulate unutilized downtime during the six months in which it is accrued;
unutilized downtime can be forwarded to the next six-month period.

     Statoil may temporarily suspend production by giving notice that specifies
the effective date of the suspension and the expected date for the resumption of
production, as well as any mobilization plan and support functions to be
maintained during the suspension period.

     Statoil may terminate the contract with immediate effect and without
penalties in the event that:

     - a force majeure situation lasts for more than 90 days

     - we become insolvent, file for bankruptcy or demonstrate through similar
       or related actions that we are not capable of performing the work or

     - we are in substantial breach of the contract

     Cancellation of the contract by Statoil entitles us to a day rate of
$85,000 per day for any remaining part of the 18-month period immediately
following the date of commencement of commercial production, as well as to
reimbursement of any unpaid monies due for production services performed and a
modification reimbursement of $12,750 per day for any remaining part of the
24-month period immediately following the date of commencement of commercial
production. Cancellation after the date of commencement of commercial production
requires a 12-month notice period.

     If either we or Statoil secure alternative work for the Petrojarl I in the
18-month period following any cancellation by Statoil without cause, then 80% of
the total compensation achieved, less actual modification and mobilization costs
for the alternative work, will be credited directly to Statoil's cancellation
liability on a half year basis.

     In the event that production is less than 50 percent of the volumes
described in the contractual production profile for more than five consecutive
days due to circumstances which are not the responsibility of Statoil, Statoil
will have the option to instruct us to stop production and perform rectification
work, during which work compensation will be treated as if the stop in
production was our responsibility.

                                        28
<PAGE>

PRODUCTION SERVICES OPERATIONS

     We provide complete project management, operations and maintenance services
for every phase in the production of an oil or gas field through our production
services operations, which are headquartered in Aberdeen, Scotland. Through
these operations we provide:

     - process facilities and asset management services, with an emphasis on
       logistics management and cost control

     - facilities maintenance and materials management services

     - facilities engineering services, from the design phase through
       commissioning

     - information management systems services, including procurement, project
       management and personnel management systems

     - mature asset management services, where we attempt to extend asset life
       and reduce operating costs for oil and gas field owners through our
       engineering expertise

OTHER BUSINESS OPPORTUNITIES

     We pursue various oil and gas business opportunities, typically in
conjunction with utilization of our geophysical expertise. We intend to continue
to pursue such opportunities and, in connection therewith, to provide technical
consulting services, reservoir studies, enhanced recovery services, prospect
identification, seismic data interpretation, seismic data reprocessing services
or other geophysical services in exchange for cash or other forms of
compensation. In this manner, we have acquired and may continue to acquire
various interests in exploration and production companies and in oil and gas
properties or concessions. The revenue from and value of these interests depend
upon the operations of the entities or properties acquired.

     In December 1996, we received, in exchange for interests in some of our
seismic data, shares in Spinnaker Exploration Company, an independent energy
company engaged in the exploration, development and production of natural gas
and oil in the Gulf of Mexico. In December 2000, we sold our entire equity
interest in Spinnaker for net proceeds of $150.5 million.

     We also consider from time to time acquisitions in areas that complement
our existing portfolio of services to the oil and gas industry.

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 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 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 financial statements in
Item 18 of this annual report.

COMPETITION

     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 and crew availability. In
addition, the first company to acquire multi-client seismic data in an area
generally has a competitive advantage in that area. Our largest competitor on a
global basis is WesternGeco, a joint venture between Schlumberger Limited and
Baker Hughes Incorporated.

     All of our major competitors in seismic data acquisition both acquire and
process 3D seismic data. Our processing operations compete primarily with
Compagnie Generale de Geophysique, S.A., WesternGeco and Veritas for time
processing contracts. We compete for time processing contracts based
                                        29
<PAGE>

primarily on price, but processing capacity and turnaround time, technology and
processing center location are also important factors.

     Our FPSO operations will generally compete from time to time with other
FPSO operators, with fixed installations and tension leg platforms, with subsea
production installations and with semi-submersible and jack-up platforms.
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. In addition to the FPSO operations and other offshore production
systems of the major oil and gas companies, our FPSO competitors include
numerous companies that own a small number of FPSO vessels.

CUSTOMERS

     Our major customers include multi-national oil and gas companies, foreign
national oil and gas companies, major independent oil and gas companies and
seismic marketing companies. For the years ended December 31, 2001 and 2000, two
customers accounted for 14% and 11% (2001) of our revenue and 16% and 11% (2000)
of our revenue; both customers utilized both geophysical and production
services. For the year ended December 31, 1999, one customer accounted for
approximately 16% of our revenue, all of which was production services revenue.
Due to the nature of our operations, significant portions of future revenue may,
from time to time, be attributable to a few customers.

SEASONALITY

     Please read "Operating and Financial Review and Prospects -- Overview of
Our Business -- Seasonality" in Item 5 of this annual report for a description
of how seasonality and weather affect our business.

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. We also carry insurance against the
destruction of or damage to our vessels and equipment in amounts, generally
equal to replacement value, that we consider adequate. From time to time,
however, we may not be able to obtain insurance against all risks or for
equipment located in all geographic areas. Under the terms of our vessel
charters, we are not generally responsible for damage to chartered vessels.

     We have established our own captive insurance company to provide insurance
for our seismic equipment, some of our production equipment and limited business
interruption. As noted below, this insurance is subject to deductibles and
limits on coverage and is supplemented by commercial reinsurance arrangements.

     We obtain a substantial portion of our casualty insurance through this
wholly-owned captive insurance company. This company retains risk of $2.5
million for each accident, with a maximum risk retention of $5.4 million per
year. Our various operating companies also retain levels of risk when obtaining
this casualty insurance from the captive company, ranging from $1 million to $2
million per accident for our FPSOs and up to $200,000 per accident for our
streamers.

     We have filed approximately $50.0 million in insurance claims for the
Ramform Banff related to weather-related damage incurred in 2000. During 2001,
we recovered $35.0 million on these claims, with the remainder expected to be
resolved over the course of 2002. These insurance recoveries offset certain
capital expenditures that we incurred on the Ramform Banff to repair the
weather-related damage.

                                        30
<PAGE>

INTERNATIONAL OPERATIONS

     We are conducting the majority of our operations in the North Sea and
offshore South America and West Africa. We also conduct significant business
operations in other areas of the world from time to time, including:

     - the Gulf of Mexico

     - offshore Australia, Indonesia and other countries in the Asia Pacific
       region

     - offshore and onshore in the Middle East

     - the Caspian Sea area

     - offshore China and Korea

     - offshore and onshore India and Pakistan

     - the Sakhalin area of Russia

     - offshore Canada

     - offshore and onshore Mexico and Latin America

     - the US mid-continent, Rocky Mountain and Alaskan North Slope regions

Please read "-- Seismic Background," "-- Seismic Data Acquisition," "-- Seismic
Data Processing Operations" and "-- FPSO Operations" above and "Key
Information -- Risk Factors -- Risk Factors Relating to Our Business
Operations -- Because we conduct a substantial amount of international
operations, we have exposure to those risks inherent in doing business abroad"
in Item 3 of this annual report. Please read note 20 of the notes to our
financial statements in Item 18 of this annual report for information regarding
the geographic mix of our operations.

GOVERNMENTAL REGULATION

     In the North Sea, we are required to obtain licenses to acquire
multi-client seismic data. We currently have licenses to conduct such activities
in portions of the Norwegian, UK and Irish territorial waters. In other areas of
the world, licensing requirements vary widely. There are no such licensing
requirements in the Gulf of Mexico, offshore Brazil or in the onshore areas
where we operate, although we are required to obtain permits for our operations.
We believe that our relations with the licensing and permitting authorities are
good.

     In addition, our operations are affected by the licensing activities 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 from the newly
licensed areas. 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, the timing and extent of these licensing rounds tend to be
irregular. The length of the actual license to explore for oil and gas varies
from region to region and is subject to governmental regulation.

     We have acquired multi-client seismic data offshore Norway covering areas
that could be awarded in the 17th licensing round that is expected to occur
during the second half of 2002. Additionally, we are awaiting consummation of
production sharing arrangements between certain customers and the government of
Brunei. Each of these events, if and when they occur, could generate significant
revenue for us.

                                        31
<PAGE>

     Our operations are affected by a variety of other laws and regulations,
including laws and regulations relating to:

     - the protection of the environment

     - exports and imports

     - occupational health and safety

     - permitting or licensing agreements for oil and gas exploration,
       development and production activities

     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 -- Unpredictable
changes in governmental regulations could increase our operating costs and
reduce demand for our services" in Item 3 of this annual report.

SUBSIDIARIES AND AFFILIATED COMPANIES

     We provide in the following table a list of our subsidiaries and affiliated
companies as of April 30, 2002.

<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 Consultants AS................................  Norway               100%
Multiklient Invest AS.......................................  Norway               100%
Pertra AS...................................................  Norway               100%
Petroleum Geo-Services, Inc. ...............................  United States        100%
Petroleum Geo-Services, Ltd. ...............................  United Kingdom       100%
Seahouse Insurance Ltd. ....................................  Bermuda              100%
PGS Multiclient Seismic Ltd. ...............................  Jersey               100%
PGS Mexicana SA de CV.......................................  Mexico               100%
PGS Rio Bonito..............................................  Brazil                99%
Dalmorneftegeofizika PGS AS.................................  Norway                49%
Walther Hervig AS...........................................  Norway                50%
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 Reservoir Consultants, Inc..............................  United States        100%
PGS Capital, Inc............................................  United States        100%
Diamond Geophysical Services Company........................  United States        100%
PGS Exploration Ltd. .......................................  Nigeria              100%
Atlantis Holding Norway AS..................................  Norway               100%
PGS Offshore Technology AS..................................  Norway               100%
PGS Tensor Middle East SAE..................................  Egypt                100%
PGS Data Processing Inc. ...................................  United States        100%
PGS Intervention AS.........................................  Norway               100%
PGS Asia Pacific Pte. Ltd. .................................  Singapore            100%
PGS Australia Pty. Ltd. ....................................  Australia            100%
Atlantis Isis Ltd. .........................................  United Kingdom       100%
PGS Consulting AS...........................................  Norway               100%
UNACO AB....................................................  Sweden               100%
</Table>

                                        32
<PAGE>

<Table>
<Caption>
NAME                                                           JURISDICTION     OWNERSHIP
----                                                           ------------     ---------
<S>                                                           <C>               <C>
Hara Skip AS................................................  Norway               100%
PGS Tensor Geofisica de Venezuela CA........................  Venezuela            100%
Atlantic Explorer AS........................................  Norway               100%
PGS Exploration SDN BHD.....................................  Malaysia             100%
PGS Exploration, Inc. ......................................  United States        100%
PGS Ocean Bottom Seismic, Inc. .............................  United States        100%
PGS Exploration Ltd. .......................................  United Kingdom       100%
PGS Floating Production Ltd. ...............................  United Kingdom       100%
PGS Pension Trustee Ltd. ...................................  United Kingdom       100%
PGS Tigress Ltd. ...........................................  United Kingdom       100%
PGS Reservoir Consulting Ltd. ..............................  United Kingdom       100%
Atlantis Technology Services Ltd. ..........................  United Kingdom       100%
Atlantic Explorer Ltd.......................................  Isle of Man           50%
Atlantis Technology Services Tunisia AS.....................  Norway               100%
Atlantis Technology Services Ajman AS.......................  Norway               100%
Atlantis Ras Al Khaimah AS..................................  Norway               100%
Oslo Seismic Services Inc. .................................  United States        100%
Oslo Explorer Plc...........................................  Isle of Man          100%
Oslo Challenger Plc.........................................  Isle of Man          100%
PGS Shipping Ltd. ..........................................  Isle of Man          100%
PGS Onshore, Inc............................................  United States        100%
PGS Production, Inc. .......................................  United States        100%
PGS Americas, Inc. .........................................  United States        100%
Seismic Energy Holding, Inc. ...............................  United States        100%
PGS Caspian AS..............................................  Norway               100%
PGS Multiclient Services, Inc. .............................  United States        100%
Atlantis Ltd. ..............................................  United Kingdom       100%
PGS Marine Services Ltd. ...................................  Isle of Man          100%
Atlantis Argyll AS..........................................  Norway               100%
Golar-Nor Offshore AS.......................................  Norway               100%
Golar-Nor Offshore Ltd. ....................................  United Kingdom       100%
K/S Petrojarl I AS..........................................  Norway              98.5%
Golar-Nor Ltd. .............................................  United Kingdom       100%
Deep Gulf LLC ..............................................  United States       50.1%
PGS Nopec Ltd. .............................................  United Kingdom       100%
PGS Production Group Ltd. ..................................  United Kingdom       100%
Atlantic Power & Gas Engineering Ltd........................  United Kingdom       100%
PGS Nominees Ltd. ..........................................  United Kingdom       100%
PGS Production Ltd. ........................................  United Kingdom       100%
PGS Production Ltd. ........................................  Jersey               100%
Atlantic Resourcing Ltd. ...................................  United Kingdom        60%
J.V. I Ltd. ................................................  United Kingdom       100%
Atlantic Power International Ltd. ..........................  United Kingdom       100%
Petrojarl 4 DA..............................................  Norway             99.25%
SOH, Inc. ..................................................  United States        100%
JV O'Hare Ltd. .............................................  United Kingdom        50%
PGS Trust I.................................................  United States        100%
PGS Trust II................................................  United States        100%
PGS Trust III...............................................  United States        100%
MJIVI.......................................................  Brunei                50%
Atlantic Power de Venezuela SA..............................  Venezuela             85%
OGIS........................................................  Malaysia              50%
</Table>

                                        33
<PAGE>

<Table>
<Caption>
NAME                                                           JURISDICTION     OWNERSHIP
----                                                           ------------     ---------
<S>                                                           <C>               <C>
ASJV Venezuela SA...........................................  Venezuela            100%
PGS Nusantara PT............................................  Indonesia            100%
Triumph Petroleum...........................................  United States      37.59%
FW Oil Exploration, LLC.....................................  United States         63%
PGS Processing Ltd. ........................................  Angola               100%
Seismic Exploration Ltd. ...................................  Canada               100%
Monsoon Ship Management.....................................  Cyprus               100%
Sakhalin Petroleum Plc......................................  Cyprus               100%
Ikdam Production, SA........................................  France                40%
PGS Investigacao Petrolifera Limitada.......................  Brazil                99%
</Table>

                                        34
<PAGE>

ITEM 5.  OPERATING AND FINANCIAL REVIEW AND PROSPECTS

     You should read the discussion under this caption in combination with our
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 financial statements 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 OF OUR BUSINESS

  HOW WE CATEGORIZE OUR BUSINESS

     The services we provide may be divided into two general categories
consisting of:

     - geophysical services, which includes:

      - seismic data acquisition and processing, and

      - reservoir characterization, monitoring and consulting services

     - production services, which includes:

      - floating production, storage and offloading, or FPSO, operations, and

      - production management services

  KEY FACTORS IMPACTING 2001 RESULTS

     You should consider the following unusual or significant items and the
following events, developments and factors in considering our results for 2001:

     - an increased focus by our geophysical services operations on the contract
       seismic market, consistent with our goal of increasing cash flow

     - our completion during 2001 of significant construction or upgrade
       projects for our FPSO vessels Ramform Banff, Petrojarl I and Petrojarl
       Foinaven, resulting in all of those FPSO vessels being operational at the
       end of 2001

     - unusual items aggregating $105.9 million, including a $138.5 million gain
       from the sale of our data management business, $13.2 million of
       multi-client library impairment charges and $19.4 million in litigation
       costs and reorganization costs

     - $65.9 million in valuation allowance charges related to deferred tax
       assets

     - $18.0 million of charges relating to the fair value of tax equalization
       swap contracts

     - $14.4 million in net gains associated with the resolution of various tax
       contingencies

     - the deferral of revenue associated with the adoption of SAB No. 101 and
       its application to our volume seismic data licensing arrangements

     During November 2001, we entered into an agreement with Veritas DGC Inc. to
combine our businesses under a new holding company. This proposed transaction is
described in more detail under "Information on the Company -- Recent
Developments -- Combination with Veritas" in Item 4 and note 3 of the notes to
our financial statements in Item 18 of this annual report.

     During January 2002, we entered into a definitive agreement to sell our
Atlantis subsidiary. Please read "Information on the Company -- Recent
Developments -- Sale of Atlantis" in Item 4 and note 3 of the notes to our
financial statements in Item 18 of this annual report for additional information
relating to this proposed transaction.
                                        35
<PAGE>

  SEASONALITY

     Our geophysical services business experiences seasonality as a result of
weather-related factors. Our first and fourth quarters, in particular, are
generally negatively affected by adverse weather conditions in the North Sea,
which prevent the full operation of seismic crews and vessels. During these
periods, we generally repair our seismic vessels and relocate them to areas with
more favorable weather conditions to conduct seismic activities. 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 gas companies. In addition,
licensing activities and oil and gas lease sales may affect quarterly operating
results. Our FPSO and production services business generally does not experience
material seasonality.

CRITICAL ACCOUNTING POLICIES

  OVERVIEW

     The preparation of our consolidated financial statements and the
application of our accounting policies requires us to make difficult, subjective
and sometimes complex estimates, assumptions and judgments about matters that
are inherently uncertain. These estimates, assumptions and judgments affect the
amounts of assets and liabilities that we report and our related disclosure of
contingent assets and liabilities. In addition, these estimates, assumptions and
judgments can have a material effect on the amount of revenue and expenses that
we report during a particular period. We base our estimates, assumptions and
judgments on historical experience and on various other assumptions that we
believe to be reasonable under the circumstances. We evaluate our estimates on a
periodic basis, and our estimates, assumptions and judgments may change as new
events occur, as more experience is acquired, as additional information is
obtained and as our operating environment changes. Actual amounts may differ
from these estimates, assumptions and judgments under different assumptions or
conditions.

     We believe the following accounting policies, which are summarized below,
are among the most critical in the preparation and evaluation of our financial
statements:

     - accounting for our multi-client data sales and amortization

     - accounting for our revenue transactions other than multi-client
       transactions

     - accounting for our derivative financial instruments

     - accounting for our income taxes

     - accounting for our long-lived assets

     For a description of our significant accounting policies, please read note
2 of the notes to our financial statements included in Item 18 of this annual
report.

  ACCOUNTING FOR OUR MULTI-CLIENT DATA SALES AND AMORTIZATION

     The accounting for our multi-client data sales and our multi-client data
library is probably the most significant of our accounting policies. We derive a
substantial portion of our revenue from sales of multi-client seismic data.
Revenue from sales of multi-client data is:

     - in the form of prefunding, defined as amounts funded by customers prior
       to or during the acquisition phase, recognized as revenue on a
       percentage-of-completion basis by evaluating the progress to date

                                        36
<PAGE>

     - in the form of licenses of data from our multi-client library that are
       recognized as revenue when we enter into a license agreement for specific
       data with the customer, the customer has been granted access to the
       licensed data and collection is reasonably assured

     - in the form of volume sales agreements related to portions of our
       multi-client library within a defined geographical area that are
       recognized as revenue, based on a ratable portion of the total volume
       sales agreement revenue, when we enter into a license agreement with the
       customer for specific data covered by the agreement, the customer has
       been granted access to the licensed data and collection is reasonably
       assured

     For multi-client surveys, we typically obtain prefunding that covers only a
portion of the costs of the surveys from a small number of oil and gas companies
that desire to obtain seismic data in the areas to be covered by the surveys. As
a result, we assume the risk that future sales of such data may not ultimately
cover the remaining costs. We capitalize as an asset on our balance sheet the
direct and indirect costs of acquiring and processing multi-client data, which
we refer to as our multi-client library, and we charge such costs to operating
expense periodically based on a percentage of current period multi-client
revenue to total estimated multi-client revenue, which estimates are updated at
least annually. Under our accounting policies, we also amortize these costs at
minimum rates based on a 5 to 8 year life and periodically evaluate our
multi-client library for impairment.

     In determining the ordinary amortization rates applied to and the fair
value of surveys in our multi-client library, we consider expected future
multi-client sales and market developments as well as past experience. Our sales
expectations include consideration of geographic location, prospectivity,
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. To the extent that
these sales expectations prove to be higher than actual sales, our future
operations will reflect lower profitability due to increased amortization rates
applied to the multi-client library in later years. Our ability to recover costs
included in the multi-client library through sales of the data depends upon
continued demand for the data and an absence of technological changes or other
developments that would render the multi-client data obsolete or less valuable.

     The financial impact for 2001 of our policies regarding amortization,
including minimum amortization, and testing our multi-client library for
impairment are discussed below under "-- Results of Operations -- Fiscal 2001
Compared with Fiscal 2000."

     The following table presents our multi-client library as of December 31,
2001, allocated by the year in which the components were completed:

<Table>
<Caption>
                                                                 NET BOOK
                                                                  VALUE
                                                              --------------
                                                              (IN THOUSANDS)
<S>                                                           <C>
Completed surveys:
Completed before 1996.......................................     $  4,297
Completed during 1996.......................................       20,954
Completed during 1997.......................................       22,835
Completed during 1998.......................................       69,730
Completed during 1999.......................................      188,373
Completed during 2000.......................................      234,824
Completed during 2001.......................................      300,095
                                                                 --------
  Completed surveys.........................................      841,108
Surveys in progress.........................................       76,964
                                                                 --------
Multi-client library........................................     $918,072
                                                                 ========
</Table>

                                        37
<PAGE>

     The table below presents the application of our minimum amortization
requirements to our multi-client library as of December 31, 2001. These minimum
amortization requirements are calculated as if there will be no future sales
from this multi-client library. We believe the likelihood of recording these
precise minimum amortization amounts is remote because we expect that
amortization generated by multi-client sales in the ordinary course of business
will substantially reduce the book value of our multi-client library. We have
incurred minimum amortization charges in the past and may incur additional
minimum amortization charges in the future, depending on the timing and
geographic mix of our multi-client sales.

<Table>
<Caption>
                                                                 MINIMUM
                                                                  FUTURE
                                                               AMORTIZATION
                                                              --------------
                                                              (IN THOUSANDS)
<S>                                                           <C>
During 2002.................................................     $100,234
During 2003.................................................      171,092
During 2004.................................................      187,120
During 2005.................................................      145,589
During 2006.................................................      130,335
During 2007.................................................       98,516
During 2008.................................................       73,898
During 2009.................................................       11,288
                                                                 --------
Future amortization.........................................     $918,072
                                                                 ========
</Table>

     Because our minimum amortization requirements apply to the multi-client
library on a component basis rather than in the aggregate, we may incur minimum
amortization charges in a year even if the aggregate amount of ordinary
amortization charges that we recognize exceeds the aggregate minimum
amortization charges.

     We monitor our minimum amortization requirements on a quarterly basis.
During the second quarter of each year, we begin to record minimum amortization
charges, using revenue estimates for the remainder of the current year to
project the maximum book value of each multi-client library component. However,
the majority of our minimum amortization charges are recorded during the fourth
quarter of each year due to the inherent imprecision in estimating current year
revenue.

  ACCOUNTING FOR OUR REVENUE TRANSACTIONS OTHER THAN MULTI-CLIENT

     We recognize revenue on proprietary, or 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. We generally recognize revenue from our floating
production services in two components: tariff-based revenue, based on the number
of barrels that we produce, is recognized as the production occurs; and day-rate
revenue is recognized over the passage of time. We recognize revenue from our
production management services as we perform the services; any performance-based
incentive fees are recognized as revenue when objective evidence indicates that
the performance criteria have been met.

  ACCOUNTING FOR OUR DERIVATIVE FINANCIAL INSTRUMENTS

     The primary form of derivative financial instrument that we utilize is the
forward foreign exchange contract. We do not engage in derivative financial
instrument transactions for speculative purposes. Although our derivative
financial instruments are economic hedges, we do not have any derivative
financial instruments that qualify for hedge accounting treatment. Accordingly,
we recognize periodic adjustments necessary to reflect the fair value of these
instruments in our financial position. We recognize these adjustments through
our results of operations as the fair value changes occur. We base the fair
value estimates used to recognize these instruments on valuations that are
performed by a third party and, at defined period-ends, on the settlements
called for by the terms of the derivative financial instruments.

                                        38
<PAGE>

  ACCOUNTING FOR OUR INCOME TAXES

     We evaluate the need for valuation allowances for our deferred tax assets
by considering the evidence regarding the ultimate realization of those recorded
assets. We record any required valuation allowances through charges that are
classified as provision for income taxes. Currently, we are recording valuation
allowances for 100% of net deferred tax assets in jurisdictions other than
Norway due to cumulative losses in recent years in those jurisdictions. Because
of these cumulative losses, we have concluded that it is not more likely than
not that the net deferred tax assets in those jurisdictions will be realized,
and are recognizing the valuation allowances accordingly. However, we believe
that we have valid tax planning strategies that may ultimately be successful in
using those net deferred tax assets. To the extent that we continue to generate
non-Norwegian deferred tax assets, we will continue to provide 100% valuation
allowances on those assets. With regard to our Norwegian net deferred tax
assets, we have concluded that a valuation allowance is not required based on
management's expectations about the generation of taxable income in Norway from
contracts that are currently in effect. We intend to monitor the Norwegian
deferred tax assets closely to determine whether taxable income will be
sufficient to realize these assets. If we determine that it is more likely than
not that the Norwegian deferred tax assets will not be realized, we will provide
a valuation allowance on the excess of the deferred tax assets over taxable
income.

  ACCOUNTING FOR OUR LONG-LIVED ASSETS

     We evaluate the seismic surveys in our multi-client library for impairment
on an annual basis by comparing the total expected future sales (less selling
expenses) to the remaining survey book value. During the years ended December
31, 2001 and 2000, we recorded $13.2 million and $166.5 million, respectively,
in multi-client library impairment charges. We evaluate our property and
equipment, goodwill and other long-lived assets for impairment whenever events
or changes in circumstances indicate that the carrying amounts may not be
appropriate. We base these evaluations on a comparison of the assets' fair
values, which are generally based on forecasts of cash flows associated with the
assets, to the carrying amounts of the assets. Any impairment is recorded as the
difference between the carrying amounts and the fair values. During the years
ended December 31, 2000 and 1999, we recorded $148.8 million and $38.4 million,
respectively, in impairment charges related to property and equipment and other
long-lived assets. We have not recognized any impairment charges related to our
goodwill. Our expectations regarding future sales and undiscounted cash flows
are highly subjective, cover extended periods of time, and are dependent on a
number of factors outside our control, such as changes in general economic
conditions, laws and regulations. Accordingly, these expectations could differ
significantly from year to year.

RESTATEMENTS

     As more fully described in note 24 of the notes to our financial statements
included in Item 18 of this annual report, our financial statements and related
disclosures as of and for the years ended December 31, 2000 and 1999 have
previously been restated to:

     - reflect fair value accounting for tax equalization swap contracts entered
       into in 1998 and 1999 to hedge our exposure to Norwegian taxes arising
       out of the conversion, for Norwegian tax purposes, of our US dollar
       denominated debt into Norwegian kroner

     - reflect the adoption of SAB No. 101, which became effective January 1,
       2000, to our revenue recognition policy for some types of volume seismic
       data licensing arrangements

     Our financial statements and related disclosures as of and for those years
included in this annual report have been further restated as described in note
24 to:

     - properly capitalize interest cost associated with the upgrade of FPSO
       vessels

     - properly reflect property and equipment, multi-client library and
       depreciation and amortization related to two of our seismic vessels

                                        39
<PAGE>

     - reflect uncertainties regarding the future utilization of deferred tax
       assets in the form of a valuation allowance against these tax assets

     - properly amortize multi-client library in accordance with our minimum
       amortization policy

     - properly amortize deferred assets over their useful lives and accrue
       defined benefit pension obligations, commission/royalty liabilities and
       lease liabilities as incurred

     We initially filed our financial statements and related disclosures as of
and for the years ended December 31, 2000 and 1999 in June 2001 as part of our
annual report on Form 20-F for the year ended December 31, 2000. In February
2002, we filed a Form 20-F/A that restated those previously issued financial
statements for the tax equalization swap contract and SAB No. 101 issues
described above. In March 2002, we announced the remaining restatement items,
but did not file an additional Form 20-F/A for these items. We summarize in the
table below the effects of all the restatements on our initially reported
results of operations included in our financial statements for the indicated
periods:

<Table>
<Caption>
                                                        YEARS ENDED DECEMBER 31,
                                         -------------------------------------------------------
                                                    2000                         1999
                                         --------------------------   --------------------------
                                                       AS INITIALLY                 AS INITIALLY
                                         AS RESTATED     REPORTED     AS RESTATED     REPORTED
                                         -----------   ------------   -----------   ------------
                                                  (IN THOUSANDS, EXCEPT PER SHARE DATA)
<S>                                      <C>           <C>            <C>           <C>
Revenue................................  $  913,482     $  906,233     $788,160       $788,160
Cost of sales..........................     432,457        423,121      333,060        333,060
Depreciation and amortization..........     263,589        258,484      238,576        238,576
Selling, general and administrative
  costs................................      76,473         75,938       71,738         71,738
Total operating expenses...............   1,144,976      1,130,000      749,088        749,088
Operating profit (loss)................    (231,494)      (223,767)      39,072         39,072
Financial expense, net.................    (134,599)      (122,933)     (95,969)       (95,969)
Other income (expense), net............     (32,774)        28,583       (9,144)        23,650
Loss before income taxes...............    (337,716)      (256,966)     (70,976)       (38,182)
Income tax benefit.....................    (132,756)       (69,392)     (57,137)       (41,890)
Income (loss) before cumulative effect
  of accounting change.................    (204,960)      (187,574)     (13,839)         3,708
Cumulative effect of accounting change,
  net of tax...........................      (6,555)            --      (19,977)       (19,977)
Net loss...............................    (211,515)      (187,574)     (33,816)       (16,269)
Basic loss per share before cumulative
  effect of accounting change..........       (2.01)         (1.84)       (0.15)          0.04
Cumulative effect of accounting change
  per share............................       (0.06)            --        (0.21)         (0.21)
Basic loss per share...................       (2.07)         (1.84)       (0.36)         (0.17)
Diluted loss per share before
  cumulative effect of accounting
  change...............................       (2.01)         (1.84)       (0.15)          0.04
Cumulative effect of accounting change
  per share............................       (0.06)            --        (0.21)         (0.21)
Diluted loss per share.................       (2.07)         (1.84)       (0.36)         (0.17)
</Table>

The discussion below of results of operations for the years 2001, 2000 and 1999
gives effect to these restatements.

                                        40
<PAGE>

RESULTS OF OPERATIONS

  FISCAL 2001 COMPARED WITH FISCAL 2000

     Revenue for 2001 of $1,052.6 million was 15% greater than revenue for 2000.
The revenue mix between geophysical services and production services was 56% and
44%, respectively, compared to a prior year revenue mix of 51% and 49% for
geophysical services and production services, respectively. The change in our
revenue mix for 2001 primarily resulted from an improved contract seismic
market.

     Geophysical services revenue for 2001 totaled $594.5 million, which was 29%
greater than revenue for 2000. Excluding data management revenue from the prior
year, geophysical services revenue for 2001 was 35% greater than the prior year
revenue. The increase in 2001 geophysical services revenue was attributable to a
higher level of contract seismic activity due to our increased emphasis on this
part of our business -- contract seismic revenue for 2001 was 93% greater than
comparable 2000 revenue. Multi-client seismic revenue for 2001 was $239.4
million, which was 4% less than the prior year revenue and reflected a reduction
in multi-client investment levels and associated prefunding revenue.
Multi-client prefunding revenue for 2001 was 26% lower than the prior year
revenue. Multi-client late sales for 2001 were 11% greater than late sales for
2000, with sales from the Asia Pacific, UK and Norway regions contributing the
greatest increases. The results of geophysical services for 2001 do not include
$26.0 million in volume data licensing arrangements that will be recognized as
revenue after December 31, 2001 due to the application of our revenue
recognition policy.

     Production services revenue for 2001 totaled $458.1 million, which was 2%
greater than the prior year revenue. The revenue figures reflected the
completion in 2001 of significant construction and upgrade projects related to
Ramform Banff, Petrojarl I and Petrojarl Foinaven and the resumption of
production from all of those FPSO vessels back into production.

     Beginning in the 2000 fourth quarter, Ramform Banff undertook a performance
upgrade to correct vessel roll motion problems. This upgrade project was
completed during the 2001 first quarter, and Ramform Banff operated with greater
than 99% uptime performance over the remainder of the year. However, the
financial performance of the vessel continues to suffer due to relatively low
levels of production. For the period of 2001 in which it operated, the Ramform
Banff produced at roughly 15% of its capacity due to low oil production from the
Banff field. We are evaluating an alternative production solution for the Banff
field and are seeking to redeploy the Ramform Banff elsewhere. We may incur
future operating losses from the Ramform Banff. We will re-evaluate the need for
loss contract accruals for the Ramform Banff in future periods.

     Also beginning in the 2000 fourth quarter, the processing facilities of the
Petrojarl I were upgraded (a) to enable gas injection capabilities, (b) to
improve the vessel's water injection capabilities, and (c) to maintain regular
class certification to qualify the vessel for a lifetime extension of 15-20
years under Norwegian Shelf conditions. This upgrade project was completed
during the 2001 second quarter and Petrojarl I began production on the Glitne
field during the 2001 third quarter.

     During portions of the 2001 second and third quarters, Petrojarl Foinaven
undertook a production capacity upgrade that increased its maximum throughput
capacity from 144,000 to 180,000 barrels of liquids per day.

     Cost of sales, including research and technology costs, for 2001 was $100.6
million, or 23%, greater than cost of sales for the prior year. Cost of sales as
a percentage of revenue was 51% for 2001, compared to 48% for 2000. The increase
in cost of sales reflected both a decrease in costs capitalized into the multi-
client library and oil and gas assets and an increase in operating cost of
sales, due primarily to an increase in the acquisition of seismic data on a
contract basis during 2001 rather than on a multi-client basis. Capitalized
costs decreased by $24.0 million, or 6%. Operating cost of sales, including
research and technology costs, increased by $76.7 million, or 9%, between 2001
and 2000. Excluding cost of sales associated with our data management business
from both 2001 and 2000, capitalized costs decreased by $17.6 million, or 5%,
and operating cost of sales, including research and technology costs, increased
by $104.8 million, or 13%.
                                        41
<PAGE>

     Geophysical services cost of sales increased by $84.2 million during 2001.
This increase included a $52.1 million, or 15%, decrease in costs capitalized
into the multi-client library and a $32.1 million, or 6%, increase in operating
cost of sales, reflecting our decreased emphasis on multi-client seismic
activity and our increased emphasis on contract seismic activity during 2001.
Excluding cost of sales associated with our data management business, which
prior to its sale in early 2001 was included as part of the geophysical services
segment, from both 2001 and 2000, capitalized costs decreased by 13% and
operating cost of sales increased by 12%.

     Production services cost of sales increased by $16.4 million during 2001.
This $16.4 million increase included a $28.1 million, or 90%, increase in costs
capitalized into oil and gas assets and a $44.5 million, or 16%, increase in
operating cost of sales. The increase in capitalized costs reflected the
progress of our Atlantis subsidiary toward active production on several fields.
The increase in operating cost of sales partly reflected gain items recognized
during 2000: an approximate $12.0 million change in interest gain related to our
investment in Spinnaker Exploration Company and recognized prior to the sale of
this investment and an approximate $10.0 million gain related to the resolution
of contingencies associated with our 1998 purchase of the Petrojarl Foinaven and
Petrojarl I. Excluding the effect of these 2000 gain items, production services
operating cost of sales increased by $22.5 million, or 7%, during 2001,
reflecting the increased production from our upgraded FPSO vessels.

     Depreciation and amortization for 2001 increased by $70.9 million, or 27%,
compared to the prior year. Depreciation and amortization represented 32% and
29% of 2001 and 2000 revenue, respectively. Amortization of the multi-client
library increased by $52.8 million, or 37%, during 2001. This increase included
$39.1 million in minimum amortization for 2001, compared to $2.2 million in
minimum amortization for 2000. A portion of the minimum amortization charges
should be viewed in relation to our revenue recognition policy for volume
seismic data licensing arrangements. Under volume seismic data licensing
arrangements generally, the customer selects data to be licensed over a defined
period of time. Under some of these arrangements, the customer commits to
license the data and pays the license fee before actually selecting the seismic
data to be licensed. However, under our revenue recognition policy we do not
recognize revenue under the arrangement until the customer actually selects the
specific data, the license period begins and collection is reasonably assured.
As of December 31, 2001, we had approximately $26.0 million of these types of
committed volume seismic data licensing arrangements that will be recognized in
revenue after December 31, 2001, but were required to calculate our 2001 minimum
amortization without taking into account the future licensing
commitment -- effectively accelerating the amortization ahead of the revenue
that has been committed for future periods.

     Excluding the effects of minimum amortization, amortization of the
multi-client library increased by $15.9 million, or 11%. The average
multi-client amortization rate during 2001 was 82%, compared to 57% for 2000.
Excluding the effects of minimum amortization, the average multi-client
amortization rate for 2001 was 65%, compared to 57% for 2000. Depreciation
increased by $18.1 million, or 15%, between 2001 and 2000, with geophysical
services depreciation increasing by $6.3 million (10%) and production services
depreciation increasing by $11.8 million (21%). The increase in geophysical
services depreciation reflected the increased emphasis on contract seismic work
during 2001, with less depreciation capitalized into the multi-client library,
and the increase in production services depreciation reflected the increased
production from our upgraded FPSO vessels.

     Selling, general and administrative costs for 2001 were $1.8 million, or
2%, greater than the prior year costs. As a percentage of revenue, these costs
were 7% and 8% for 2001 and 2000, respectively. The comparability of our
selling, general and administrative costs as a percentage of revenue for 2001
and 2000 reflected our efforts to hold these types of costs constant.

     Unusual items, net, for 2001 included $13.2 million in multi-client library
impairment charges, $19.4 million in litigation costs and reorganization costs
including severance for former members of senior management and a $138.5 million
gain on the sale of our data management business.

     Operating profit, before unusual items and minimum amortization, for 2001
was $139.2 million, 2% higher than the comparable 2000 operating profit.
Operating profit margin before unusual items and
                                        42
<PAGE>

minimum amortization for 2001 decreased slightly to 13% from the comparable 2000
margin of 15%. Including the effects of minimum amortization, operating profit
before unusual items was $100.1 million for 2001, which was 25% less than the
comparable 2000 operating profit. The associated operating profit margin was 10%
for 2001, compared to 15% for 2000.

     Geophysical services operating profit before unusual items and minimum
amortization of $47.3 million for 2001 was $14.0 million, or 42%, greater than
the comparable 2000 operating profit, reflecting the increase in contract
seismic activity during 2001. Operating profit margin before unusual items and
minimum amortization increased slightly from 7% for 2000 to 8% for 2001.
Including the effects of minimum amortization, geophysical services operating
profit, before unusual items, was $8.2 million for 2001, which was 74% less than
the comparable 2000 operating profit. The associated operating profit margin was
1% for 2001, compared to 7% for 2000.

     Production services operating profit before unusual items of $91.9 million
for 2001 was $11.3 million, or 11%, less than the comparable 2000 operating
profit. Operating profit margin before unusual items decreased from 23% for 2000
to 20% for 2001. This decrease in production services operating profit includes
the effect of the $22 million in non-recurring gain items recorded during 2000
and discussed above. Excluding the effects of these non-recurring gain items,
production services operating profit for 2001 was $10.7 million, or 13%, greater
than the comparable 2000 operating profit and the associated 2001 operating
profit margin was 20%, compared to 18% for 2000. This improvement in the 2001
operating profit reflected the completion of our FPSO upgrade projects and the
resumption of production from all of our FPSO vessels during 2001.

     Net financial expense for 2001 was $8.6 million, or 6%, greater than net
financial expense for the prior year. The increase in financial expense during
2001 was primarily due to $6.0 million in charges related to our multi-client
library securitization transaction that was executed during the 2001 second
quarter.

     Other expense, net, of $22.1 million for 2001 included $18.0 million in
fair value expense associated with our tax equalization swap contracts, compared
to $61.4 million in fair value expense for 2000.

     The $35.8 million in tax expense provided for 2001 consisted of:

     - a benefit of $40.8 million on the results of continuing operations

     - a net expense of $30.8 million associated with the $105.9 million in
       unusual items

     - net gains of $14.4 million associated with the resolution of various tax
       contingencies

     - a net benefit of $5.7 million related to tax equalization swap contracts

     - a $65.9 million valuation allowance charge related to deferred tax assets

  FISCAL 2000 COMPARED WITH FISCAL 1999

     Revenue for 2000 totaled $913.5 million, an increase of approximately 16%
over revenue for 1999. The production services segment contributed $450.9
million of 2000 revenue compared to $368.3 million for 1999. This 22% increase
in production services revenue in 2000 reflected seven additional production
months from the Petrojarl Varg, which we acquired in July 1999, and an increase
in the level of third-party platform services provided by our Atlantic Power
group. These increases were partially offset by suspended production operations
on the Petrojarl I and Ramform Banff as these FPSO systems underwent significant
upgrades during the fourth quarter of 2000. Geophysical services revenue for
2000 totaled $462.6 million and reflected an increase of 10%, or $42.8 million,
from 1999 revenue. This increase was attributable to the higher level of
contract seismic activity during the 2000 summer season. Multi-client seismic
revenue for 2000 totaled $248.2 million, an increase of 2%, or $6.0 million,
from comparable 1999 revenue.

     Cost of sales, including research and technology costs, for 2000 increased
by $90.2 million, or 26%, as compared to the prior year. Cost of sales as a
percentage of revenue was 48% for 2000 as compared to 44% for 1999. The increase
in cost of sales reflected the full year of production services from the
Petrojarl
                                        43
<PAGE>

Varg and the increase in platform services and geophysical contract seismic
activity over the year. The increase in cost of sales as a percentage of revenue
primarily reflected continued low pricing for geophysical services and an
increase in the lower margin platform services.

     Depreciation and amortization for 2000 increased by $25.0 million, or 10%,
as compared to the prior year. Depreciation and amortization represented 29% and
30% of 2000 and 1999 revenue, respectively. The increase in depreciation and
amortization reflected the full year of production services from the Petrojarl
Varg and the higher level of geophysical contract seismic services. The average
multi-client amortization rate during 2000 was 57%, which was the same as the
1999 rate.

     Selling, general and administrative costs for 2000 increased by $4.7
million, or 7%, as compared to the prior year. This increase was due in part to
a gain for the year ended December 31, 1999 from our production services group
related to resolution of a legal contingency. As a percentage of revenue, these
costs were relatively consistent at 8% and 9% for 2000 and 1999, respectively.

     Operating profit before unusual items for 2000 was $134.3 million,
representing an increase of 4% compared to 1999. Operating profit margin before
unusual items for 2000 decreased slightly to 15% from the comparable 1999 margin
of 16%.

     Production services operating profit before unusual items for 2000
increased by 48%, or $33.6 million, over operating profit for 1999. Operating
profit margin before unusual items improved from 19% for 1999 to 23% for 2000.
The improved production services operating profit resulted primarily from the
additional seven production months in 2000 from the Petrojarl Varg and greater
production in 2000 from the Petrojarl Foinaven.

     Geophysical services operating profit before unusual items for 2000
decreased by 48%, or $28.3 million, from operating profit for 1999. Operating
profit margin before unusual items declined from 14% for 1999 to 7% for 2000.
Operating profit from the geophysical services segment did not reflect the
significant, sustained rebound in oil and gas prices that occurred during 2000,
as exploration and development spending by oil and gas companies did not
increase in tandem with the oil and gas price increases. Additionally, the
depressed oil and gas company spending level resulted in lower prices for
geophysical services, and this reduced pricing also adversely affected our
operating profit. As a result of these market conditions, we reviewed the
carrying amounts of our assets and long-term contract performance and recorded
$365.8 million in unusual items for 2000 as follows:

     - $166.5 million in impairment charges against our multi-client library

     - $148.8 million in impairment charges against property, equipment and
       other assets

     - $50.5 million in losses for long-term contracts

     Although primarily related to the geophysical services segment, these
charges included $77.2 million related to the Ramform Banff and other production
assets. We believe that the upgrade of the Ramform Banff, which commenced in the
fourth quarter of 2000 and was completed in the first quarter of 2001, will
significantly improve uptime performance from this asset.

     Income from equity investments for 2000 included a $54.7 million gain
associated with the sale of our share holdings in Spinnaker Exploration Company.

     Net financial expense for 2000 increased by 40%, or $38.6 million, over net
financial expense for 1999. The increase in financial expense for 2000 was due
to (a) the issuance in March 2000 of $225.0 million in senior unsecured notes,
(b) five additional months of expense relating to our trust preferred securities
that were issued in June 1999 and (c) a higher average level of indebtedness
outstanding under our revolving bank credit facility.

     Other expense, net for 2000 included a $28.6 million increase in fair value
expense associated with our tax equalization swap contracts and $26.0 million in
gains associated with UK leases. For 1999, other expense, net included $19.1
million in gains associated with UK leases. We do not expect to recognize any
significant income or cash flows related to UK leases in future periods.
                                        44
<PAGE>

     The $132.8 million income tax benefit provided for 2000 consisted of (a) a
benefit of $14.0 million on the results of continuing operations, (b) a net
benefit of $72.3 million associated with the $365.8 million in unusual charges,
the $26.0 million UK lease gain and the $54.7 million gain on the sale of our
shares in Spinnaker, (c) a net benefit of $50.3 million related to tax
equalization swap contracts, and (d) a $3.8 million valuation allowance against
deferred tax assets.

     The cumulative effect of accounting change, net of tax, was recorded as of
January 1, 2000 and reflected our adoption of the provisions of SAB No. 101.
This accounting change related to our accounting for some types of volume
seismic data licensing arrangements and included adjustments to revenue ($22.8
million), amortization ($11.4 million) and commissions expense ($2.3 million).
The aggregate $9.1 million cumulative effect charge was reduced by a $2.5
million tax benefit.

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 in
particular the following:

     - the results of the Ramform Banff. Based on available information
       including information about the reservoir, we expect the vessel to
       continue to produce at low levels and to continue to generate losses
       through at least the third quarter of 2002. We expect one or two new
       wells to be drilled on the Banff field during 2002, and any incremental
       production from such wells will help reduce losses under the existing
       Banff contract. In order to improve the results of the Ramform Banff, we
       are evaluating moving the vessel to another location and providing an
       alternative production solution for the Banff field. Depending on whether
       and when the Ramform Banff is redeployed, we may need to provide for
       future losses on the Banff contract.

     - the benefits provided by the capacity upgrade of the Petrojarl Foinaven.
       In addition, we expect to realize additional revenue on the Foinaven
       contract since the field's reserve estimates were significantly increased
       during the 2001 fourth quarter. With the completion of several successful
       development drilling programs and 4D seismic surveys, we believe that
       Petrojarl Foinaven will remain in production on the Foinaven field for a
       substantial period of time. We anticipate that production services
       revenue for 2002 will be significantly higher than 2001 revenue, as the
       performance capability of the FPSO vessels as a group has been improved
       and there is no significant downtime planned for any of the vessels.

     - the increased demand for contract seismic operations that we experienced
       during 2001, including demand for high-density, single-source 3D surveys.
       We believe that the demand for such surveys -- supported by our Ramform
       HD3D(TM) seismic technology -- will continue to increase during 2002, as
       the industry realizes the level of operational efficiency and data
       sophistication that can be achieved through the use of HD3D(TM) seismic
       technology. The expected increase in contract seismic operations in 2002
       will likely yield lower operating profit margins than would multi-client
       operations, but we expect the contract operations to yield increased cash
       flow in the near term.

     - our substantial geophysical services backlog. In addition to a
       substantial backlog of traditional marine acquisition work at December
       31, 2001, our 2002 geophysical services backlog includes more than $100
       million in onshore and transition zone contract acquisition work, a
       substantial portion of which will be performed using our HD3D(TM) seismic
       technology, and approximately $33 million in four-component contract
       acquisition work.

     - future licensing activities in Norway (17th licensing round) and by host
       countries in West Africa and the Asia Pacific region. We expect to
       benefit from this licensing activity through uplift fees due under
       previously executed multi-client sales contracts and from the recognition
       in periods after December 31, 2001 of $26.0 million of revenue related to
       volume seismic data licensing arrangements that were committed as of such
       date.

     - whether the closing of the sale of Atlantis occurs
                                        45
<PAGE>

     - whether we are successful in reducing our outstanding debt levels and
       operating costs and improving our cash flow

     - the amount of minimum amortization charges we incur for our multi-client
       data library

     - the impact of adoption of SFAS No. 142

     - the impact of foreign currency exchange rate fluctuations and the
       resulting fair value effects on our tax equalization swap contracts and
       the related income tax expense or benefit

FINANCIAL CONDITION

  CAPITAL RESOURCES AND LIQUIDITY

  Material Factors.

     In March 2002, we entered into a $250.0 million short-term credit facility,
which was amended and restated in May 2002. The facility will mature at the
earlier of August 31, 2003 or June 16, 2003 if the Veritas transaction has been
terminated prior to that date. We must make a mandatory prepayment of $175.0
million from the future proceeds of any Atlantis sale. The credit facility
carries an initial interest rate equal to LIBOR plus a margin of 0.65%, which
margin escalates to 1.0% on June 1, 2002, to 1.5% on August 1, 2002, and to 4.5%
on October 1, 2002 until maturity. In the event that either Standard & Poor's or
Moody's downgrades our credit rating below BBB- or Baa3, respectively, prior to
October 1, 2002, the margin will escalate to 4.5% at the time that the downgrade
is issued. If any amounts are outstanding under this credit facility at July 31,
2002 (or earlier in the event of termination of the Veritas transaction prior to
July 31, 2002), we are obligated to use our best endeavors to arrange financing
in order to repay such amounts prior to maturity. Additionally, if the facility
remains outstanding at July 1, 2002, we will be required to limit any additional
cumulative capital expenditures and multi-client investments to a maximum of
$280.0 million for the period from July 1, 2002 through the maturity date of the
facility.

     We believe that our cash on hand ($86.0 million as of March 31, 2002),
operating cash flows, available bank credit facilities and the proceeds from the
sale of non-core assets, including our Atlantis subsidiary, will be sufficient
to meet the existing contractual cash obligations, anticipated multi-client
investments, anticipated capital expenditures, working capital and other
operational needs of our business for the next 12 months. Our future operating
cash flows will be affected by our future performance and will be subject to,
among others, the factors discussed under "Key Information -- Risk Factors" in
Item 3 of this annual report. If cash generated from operations and these other
expected sources is not sufficient to satisfy our liquidity requirements, we may
seek to sell either debt or equity securities, to obtain additional credit
facilities or other long-term financings or to sell assets. We cannot assure you
that such sources of funds will be available in the future or be available at
costs acceptable to us.

  Credit Ratings.

     Our senior unsecured debt credit ratings as of May 2, 2002 were as follows:

<Table>
<Caption>
RATING AGENCY       RATING
-------------       ------
<S>                 <C>
Moody's             Baa3
Standard & Poor's   BBB-
Fitch               BBB-
</Table>

     We cannot assure you that these credit ratings will remain in effect for
any given period of time or that one or more of these credit ratings will not be
lowered or withdrawn entirely by the credit rating agencies. Our credit ratings
with Moody's and Standard & Poor's are currently under review and on creditwatch
with negative implications, respectively. If we do not complete the Atlantis
sale or if we do not complete the Veritas transaction, our credit ratings may be
downgraded. We note that these credit ratings are not recommendations to buy,
sell or hold our securities and may be revised or withdrawn at any time by the
credit rating agencies. Each credit rating should be evaluated independently of
any other credit

                                        46
<PAGE>

rating. Any future reduction or withdrawal of one or more of our credit ratings
could have a material adverse impact on our ability to access capital on
acceptable terms.

     Additionally, if our credit rating declines below BBB- (Standard & Poor's)
and Baa3 (Moody's), we estimate that we could be obligated to provide up to
L35.7 million (approximately $52.0 million) in collateral or other credit
support to one or more lessors or other parties under UK leasing arrangements.
In the event that our credit ratings are downgraded to below BB+ or Ba1 by
Standard & Poor's or Moody's, respectively, we will be required to increase by
30% the quarterly redemption of the mandatorily redeemable cumulative preferred
securities of a subsidiary which owns a portion of our multi-client library. If
those credit ratings remain for a certain period of time, or deteriorate below
BB- or Ba3, respectively, we will be required to increase the quarterly
redemption of the preferred securities to an amount equal to 100% of the actual
revenue recognized from the licensing of the data held by that subsidiary.

  Credit Facilities.

     The following table summarizes the amounts owed and amounts available under
our various committed credit facilities (in millions) as of March 31, 2002. The
following table does not include approximately $40.0 million in available,
uncommitted credit lines at March 31, 2002:

<Table>
<Caption>
                                                                                MATURING
                                                  TOTAL                          BEFORE
                                                COMMITTED   DRAWN    UNUSED   DECEMBER 31,
                                                 CREDIT     AMOUNT   AMOUNT       2002
                                                ---------   ------   ------   ------------
<S>                                             <C>         <C>      <C>      <C>
Revolving bank credit facility................   $430.0     $360.0   $70.0        $--
Short-term bank facility......................    250.0      250.0      --         --
Other bank facilities.........................     21.0       20.5     0.5         --
                                                 ------     ------   -----        ---
     Total....................................   $701.0     $630.5   $70.5        $--
                                                 ======     ======   =====        ===
</Table>

  Significant Sources of Capital During 2001.

     In March 2001, we sold our global Petrobank data management business and
related software to a subsidiary of Halliburton for $165.7 million in cash,
representing gross sale proceeds of $175.0 million less a $9.3 million working
capital adjustment. The net proceeds received were used, in part, to repay
indebtedness outstanding under our revolving bank credit facility.

     In April 2001, we entered into a securitization transaction related to our
multi-client marine seismic data library. In consideration for $234.3 million in
net proceeds, we sold the ownership of a portion of this data library to a
subsidiary, which then issued $240.0 million in cumulative preferred stock to a
third-party investor. The preferred stock will be redeemed, and the preferred
dividends will be paid, solely through the proceeds received on future data
sales from the sold data. During 2001, redemption payments of $77.3 million were
made from such sales proceeds. Once the $240.0 million of preferred stock is
redeemed and the cumulative preferred dividends are paid, we will retain the
full proceeds of any remaining data sales. We used the net proceeds from the
securitization primarily to repay indebtedness outstanding under our revolving
bank credit facility.

     At December 31, 2001, we had $90.0 million available to be utilized under
our primary committed revolving bank credit facility. This unsecured $430.0
million revolving bank credit facility matures in 2003 and bears interest at
LIBOR plus a margin of either 0.35% per annum or 0.40% per annum, depending upon
the level of our indebtedness. Borrowings under this revolving bank credit
facility are subject to a material adverse change condition regarding our
financial condition and to other conditions to borrowing that are customary for
such types of facilities.

     During 2001, we also borrowed under a $75.0 million unsecured revolving
credit facility with a syndicate of banks. The facility bore interest at LIBOR,
plus a margin that escalated from 0.4% to 0.6% by maturity. This facility
matured in December 2001 and was repaid. During 2001, we borrowed under a $21.0
million unsecured bank credit facility to fund some of our oil and gas
activities. This facility bears

                                        47
<PAGE>

interest at LIBOR plus a margin that ranges from 0.63% to 1.4%, and is payable
in installments through 2003, with the payment installments tied to future
production from oil and gas assets. At December 31, 2001, $20.5 million in
short-term debt was outstanding under this credit facility.

  CAPITAL REQUIREMENTS

     Our capital requirements are affected primarily by our results of
operations, capital expenditures, investments in multi-client library, debt
service requirements, lease obligations, payments on preferred securities of
subsidiaries and working capital needs. The majority of our capital
requirements, other than debt service, lease obligations and payments on
preferred securities, consist of

     - capital expenditures on seismic vessels and equipment

     - capital expenditures on FPSO vessels and equipment

     - investments in our multi-client library

     - capital expenditures on computer processing and reservoir monitoring
       equipment

     - working capital related to the growth and seasonal nature of our business

     In prior years, our capital expenditures have related not only to normal
ongoing equipment replacement and refurbishment needs, but also to increases in
capacity in our seismic data acquisition operations and our FPSO operations.
Additional capital expenditures, some of which could be substantial, depend to a
large extent upon the nature and extent of future commitments that are
discretionary.

     The following table sets forth our consolidated capital requirements for
2001 and estimates of our consolidated capital requirements for 2002, in each
case excluding the debt service and other contractual cash obligations that are
shown in the table included later in this section (in millions):

<Table>
<Caption>
                                                               2001    2002 (ESTIMATED)
                                                              ------   ----------------
<S>                                                           <C>      <C>
Capital expenditures -- Geophysical.........................  $ 26.1        $ 45.0
Capital expenditures -- Production Services(1)..............   213.5          15.0
Investment in multi-client library..........................   230.2         190.0
                                                              ------        ------
Total.......................................................  $469.8        $250.0
                                                              ======        ======
</Table>

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

(1) Excludes Atlantis-related development costs. We expect that a substantial
    portion of these costs will be reimbursed if and when the sale of Atlantis
    closes.

     A substantial amount of our capital expenditures and investments in our
multi-client library is discretionary. We expect to substantially decrease our
capital expenditures in 2002, since there are no planned major capital projects
for our FPSO systems. We expect to reduce investments in our multi-client
library in 2002.

     Capital expenditures of $239.6 million for 2001 related primarily to the
upgrade of the Ramform Banff, Petrojarl I and Petrojarl Foinaven FPSO systems
and to oil and gas assets. Capital expenditures of $115.2 million for 2000
related primarily to ongoing maintenance capital expenditures and the upgrade of
both the Ramform Banff and Petrojarl I FPSO systems. Capital expenditures of
$667.9 million for 1999 related primarily to the acquisition of the Petrojarl
Varg in July 1999 and to final payments on the Ramform Victory, which was
delivered in January 1999, the Ramform Vanguard, which was delivered in April
1999, and the Ramform Banff, which commenced production in the first quarter of
1999.

     During 2001, our investment in multi-client library primarily related to
seismic surveys in the North Sea, offshore Brazil and West Africa and in the
Asia Pacific region. During 2000, we invested $264.5 million in our multi-client
library, primarily in strategic, deepwater seismic surveys in the North Sea,
offshore Brazil and West Africa and in the Asia Pacific region. During 1999, we
invested

                                        48
<PAGE>

$338.7 million in our multi-client library, primarily in seismic surveys in the
North Sea, the Gulf of Mexico, offshore West Africa and in the Asia Pacific
region.

     In the following table we estimate our consolidated contractual obligations
as of December 31, 2001 to make future payments for 2002 through 2004 and
thereafter (in millions). The following table does not include interest or
dividend payments on our debt and preferred securities obligations:

<Table>
<Caption>
                                                       PAYMENTS DUE BY PERIOD
                                       -------------------------------------------------------
                                                                                     2005 AND
CONTRACTUAL CASH OBLIGATIONS            TOTAL       2002        2003       2004     THEREAFTER
----------------------------           --------   --------    --------   --------   ----------
<S>                                    <C>        <C>         <C>        <C>        <C>
Short-term and long-term debt,
  including current portion..........  $2,161.3   $  257.7(1) $  599.0   $   10.2    $1,294.4
Capital lease obligations(2).........      60.9       13.1        11.2        9.2        27.4
Operating lease obligations..........     297.5      111.4        66.8       42.7        76.6
Guaranteed preferred beneficial
  interest in junior subordinated
  debt securities....................     141.0         --          --         --       141.0
Mandatorily redeemable cumulative
  preferred securities(3)............     169.3       72.0        46.1       32.6        18.6
                                       --------   --------    --------   --------    --------
Total contractual cash obligations...  $2,830.0   $  454.2    $  723.1   $   94.7    $1,558.0
                                       ========   ========    ========   ========    ========
</Table>

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

(1) Includes $225.0 million of floating rate notes that matured and were
    refinanced with a $250.0 million bank credit facility in March 2002. Such
    facility will mature in 2003.

(2) Reflects gross contractual commitments under capital leases.

(3) Assumes that our credit ratings remain at or above BB+ or Ba1 by Standard &
    Poor's or Moody's, respectively.

CURRENCY FLUCTUATIONS

     While we do not experience any significant effects from inflation, we can
experience significant currency fluctuations. The primary currencies for our
operations are the US dollar, the Norwegian kroner and the British pound. A
strengthening or weakening of the Norwegian kroner or the British pound against
the US dollar will generally have an impact on operating profit. We typically
hedge a portion of our exposure to foreign currency exchange rate fluctuations
by attempting to balance our asset and liability positions and, to a lesser
extent, by purchasing foreign currency exchange contracts and other foreign
currency exchange instruments from time to time.

     In 1998 and 1999, we entered into tax equalization swap contracts to hedge
the cash-flow risk associated with the Norwegian statutory tax effect of
unrealized foreign currency exchange rate fluctuations between the Norwegian
kroner and US dollar on our non-kroner denominated financial instruments
(primarily US dollar denominated debt and trust preferred securities). These
fluctuations are taxable/deductible on a mark-to-market basis for Norwegian
statutory tax purposes, and therefore create current tax liability/benefit
positions for us in our tax filings. The aggregate settlement for the year ended
December 31, 2001 on these contracts created an $11.4 million liability to be
paid to our counterparty during 2002. In addition to this settlement liability,
we recorded $6.6 million to other expense during 2001 to properly reflect the
fair value of these contracts. The aggregate settlement for 2000 created a $65.2
million liability which was paid during 2001. We also recorded a $3.8 million
benefit to other expense during 2000 to properly reflect the fair value of these
contracts. The aggregate settlement for 1999 created an $8.4 million liability,
which was paid during 2000. We recorded $24.4 million in additional other
expense for 1999 to properly reflect the fair value of these tax equalization
swap contracts.

     For 2001, we recorded to other expense, net, $1.7 million in net foreign
exchange losses exclusive of the effect of our tax equalization swap contracts
as the US dollar weakened against the Norwegian kroner. For 2000 and 1999, we
recorded to other expense, net, $2.9 million and $4.1 million, respectively, in
net

                                        49
<PAGE>

foreign exchange gains exclusive of the effect of our tax equalization swap
contracts as the US dollar continued to strengthen against the Norwegian kroner.

     To the extent our level of international operations and the revenue and
expenses that we generate in other currencies increases, our exposure to foreign
currency exchange rate fluctuations will also increase. These fluctuations could
have a material impact on our results of operations.

     Under Norwegian foreign exchange controls currently in effect, transfers of
capital to and from Norway are not subject to prior government approval, except
that the physical transfer of payments in currency is restricted to licensed
banks.

INCOME TAXES

     Statement of Financial Accounting Standard ("SFAS") No. 109, "Accounting
for Income Taxes," requires that our provision for income taxes be determined
based upon the liability method, in which we recognize deferred tax assets and
liabilities based on differences between the financial statement and tax bases
of assets. The liability method requires us to evaluate our deferred tax assets
for realization based on a "more likely than not" standard, and to provide a
valuation allowance where realization is not determined to be "more likely than
not." For 2001 and 2000, we provided $65.9 million and $3.8 million,
respectively, in valuation allowances against our deferred tax assets because of
uncertainties about our future ability to fully utilize net operating losses in
the US and UK.

NEW ACCOUNTING STANDARDS

     During 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other
Intangible Assets." SFAS No. 141 requires that the purchase method of accounting
be used for all business combinations initiated after June 30, 2001. Effective
beginning January 1, 2002, SFAS No. 142 suspends amortization of goodwill and
intangible assets with indefinite lives and, instead, requires an annual
impairment review based on a comparison of fair value to carrying value. SFAS
No. 142 requires the fair value determination to be completed by June 30, 2002,
with any resulting transitional impairment to be recorded by December 31, 2002
as the cumulative effect of an accounting change. Any impairments other than
transitional impairment will be recognized in continuing operations. We are
developing our fair value calculations and have not yet determined the impact of
adopting SFAS No. 142.

     During 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations". SFAS No. 143 establishes accounting and reporting standards for
the retirement of long-lived assets requiring the fair value of an asset
retirement obligation to be recognized as a liability in the period in which it
is incurred, with the associated costs capitalized as part of the carrying
amount of the long-lived asset. SFAS No. 143 is effective for us beginning
January 1, 2003, and any effects on adoption will be reflected as a cumulative
effect of an accounting change. We have not yet determined the impact on us of
SFAS No. 143.

     Also during 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses, in part,
issues related to implementation of SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 144
is effective for us as of January 1, 2002. We do not expect to recognize any
material effects on the prospective implementation of SFAS No. 144.

                                        50
<PAGE>

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

BOARD OF DIRECTORS

     The table below provides information about our directors as of May 17,
2002:

<Table>
<Caption>
                                                    DIRECTOR
NAME (AGE)                            POSITION       SINCE     TERM EXPIRES   SHARE OWNERSHIP
----------                            --------      --------   ------------   ---------------
<S>                                 <C>             <C>        <C>            <C>
Reidar Michaelsen (58)...........   Chairman          1993         2003          *
Michael S. Mathews (61)..........   Vice Chairman     1993         2003          *
Jens Gerhard Heiberg (63)........   Director          1993         2003          *
Mark G. Frantz (55)..............   Director          1994         2002          *
Jan Aage Strand (48).............   Director          1996         2002          *
Endre Ording Sund (52)...........   Director          1998         2002          *
</Table>

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

* Less than 1% of our outstanding shares as of December 31, 2001.

     Mr. Michaelsen has been chairman of the board and chief executive officer
since 1993. He was president of PGS from 1991 to 1993. Mr. Michaelsen served as
managing director of Norsk Vekst AS during the period 1989 to 1991. He headed
the Selmer Sande Group from 1986 to 1989 and was with Geco Geophysical Company,
Inc., Houston ("Geco") from 1982 to 1986, reaching the position of managing
director. Mr. Michaelsen received a degree in business economics from the
Norwegian School of Management in 1968 and an M.B.A. from the University of
Wisconsin in 1975.

     Mr. Mathews is managing director of Westgate Capital Co., a private New
York-based investment firm. From 1989 to 1992, Mr. Mathews served as managing
director of Bradford Ventures Ltd., a private investment firm involved in equity
investments, including acquisitions. Prior to 1989, he was president of DNC
Capital Corporation and senior vice president and director of its parent, DNC
America Banking Corp., the US subsidiary of Den Norske Credit Bank Group, where
he directed merchant banking and investment activity in North America and
founded and acted as senior advisor to Nordic Investors Limited, N.V., a private
venture capital fund. Mr. Mathews has been a director of numerous companies and
is currently chairman of Telecomputing ASA and Apptix ASA, both listed on the
Oslo Stock Exchange. Mr. Mathews received an A.B. from Princeton University in
1962 and received a J.D. from the University of Michigan Law School in 1965.

     Mr. Heiberg is a partner of Norscan Partners AS. From 1989 to 1994, he was
chairman of the Lillehammer Olympic Organizing Committee, responsible for the
1994 Winter Olympic Games in Lillehammer, Norway. From 1973 to 1989, he was
managing director of Aker Norcem A/S, and from 1989 to 1996, he was chairman of
its successor company, Aker ASA. Mr. Heiberg serves on the boards of several
companies, both inside and outside of Norway. Mr. Heiberg holds a degree from
the College of Commerce in Oslo and received a master's degree in business
administration from the Copenhagen Graduate School of Economics and Business
Administration.

     Mr. Frantz is chairman, chief executive officer and president of Frantz
Medical Development Ltd., Frantz Imaging Inc., FrantzTech Ltd. and Frantz Tool &
Design, Inc., a group of affiliated companies headquartered in New York
specializing in the research, development and manufacturing of medical
electronic devices and related disposables. Mr. Frantz founded Frantz Medical
Development Ltd. in 1980 and the remainder of the group companies in the late
1980s. From 1976 to 1979, Mr. Frantz was employed as the vice president of
operations of Med-Tek Ltd., a supplier of highly sophisticated medical
electronics equipment. Mr. Frantz was also employed by Pfizer Pharmaceuticals
from 1973 to 1975 in strategic planning and product management positions. Mr.
Frantz received a B.S. degree from Georgetown University in 1969 and an M.B.A.
from Columbia University in 1972.

     Mr. Strand is the founder and, since 1991, has served as managing director
of Tobine AS, a privately owned group of companies headquartered in Oslo
involved in the shipping, construction, real estate and salmon production
businesses. Mr. Strand served as senior vice president of Norsk Vekst AS during
the

                                        51
<PAGE>

period 1989 to 1991, and was Senior Vice President -- Finance of Selmer Sande
Group from 1987 to 1989. Prior to that time, Mr. Strand served as controller of
Geco AS in Oslo and worked for Peat Marwick, Mitchell & Co. Mr. Strand received
a master's degree in business administration from BedriftsOkonomisk Institutt in
Oslo.

     Mr. Sund served as chairman of Golar-Nor Offshore until its acquisition by
PGS from Awilco ASA in 1998. Mr. Sund also served as chairman of the board of
Awilco ASA from 1992 through 2000 and served as president of Awilco ASA from
1989 to 1992. Mr. Sund served as the managing director of Anders Wilhelmsen &
Co. AS from 1992 through 2000 and is a director of Kenor ASA and chairman of
Marine Provider AS and the Norwegian Shareholder Association. Mr. Sund is the
chairman and chief operating officer of Acta AS. Mr. Sund holds various other
board positions. Mr. Sund graduated from the Norwegian Naval Academy, holds a
Master Mariner's degree, studied at the Norwegian School of Management and
obtained a PMD from Harvard Business School.

AUDIT AND COMPENSATION COMMITTEES OF THE BOARD

     Our audit committee consists of Messrs. Mathews, Frantz and Strand; our
compensation committee consists of Messrs. Mathews, Frantz and Heiberg. The
audit committee reviews, acts on and reports to the board of directors with
respect to various auditing and accounting matters. With respect to auditing
matters, the committee's activities include the selection of our auditors for
shareholder approval, the scope of the annual audit, fees to be paid to the
auditors, the performance of our independent auditors and our accounting
practices. With respect to accounting matters, the committee's activities
include reviewing our interim and year-end financial condition and results of
operations and considering the adequacy of our internal accounting and control
procedures. The compensation committee establishes and reviews overall policy
and structure with respect to compensation matters, including the determination
of compensation arrangements for directors, executive officers and key employees
and the administration of our share option plans.

                                        52
<PAGE>

EXECUTIVE OFFICERS

     The table below provides information about our executive officers as of May
17, 2002:

<Table>
<Caption>
                                                                            EXECUTIVE
                                                                             OFFICER
NAME (AGE)                                         POSITION                   SINCE     SHARE OWNERSHIP
----------                                         --------                 ---------   ---------------
<S>                                 <C>                                     <C>         <C>
Reidar Michaelsen (58)............  Chief Executive Officer                   1991         *
J. Christopher Boswell (41).......  Senior Vice President and Chief           1995
                                    Financial Officer                                      *
Sam R. Morrow (53)................  Senior Vice President -- Finance and      1996
                                    Treasurer                                              *
Anthony Ross Mackewn (54).........  President -- PGS Geophysical              1999         *
Kaare Gisvold (59)................  President -- PGS Production               1998         *
Karl Andreas Berteussen (57)......  Senior Vice President -- Reservoir        1999
                                    Technology                                             *
William E. Harlan (43)............  Vice President -- Chief Accounting and    1996
                                    Administrative Officer                                 *
Knut Haavardsen (59)..............  General Counsel                           1992         *
</Table>

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

* Less than 1% of our outstanding shares as of December 31, 2001.

     Mr. Boswell was appointed Senior Vice President and Chief Financial Officer
in June 1996, and since the fourth quarter of 1995 had served as Senior Vice
President -- Control and Chief Accounting Officer. Mr. Boswell joined PGS in
October 1994 as Vice President -- Finance of PGS Exploration (US), Inc. Prior to
joining PGS, Mr. Boswell was employed by Price Waterhouse from 1989 to 1994 and
by Arthur Andersen from 1984 to 1989. Mr. Boswell received a bachelor's degree
in business administration with an emphasis on accounting from the University of
Texas at Austin in 1984.

     Mr. Morrow joined PGS in June 1996 as Senior Vice President -- Finance and
Treasurer. Prior to joining PGS, Mr. Morrow served as Chief Financial Officer of
SeaMar Inc., a supply vessel and marine management company, from 1995 to 1996.
From 1993 to 1994, Mr. Morrow served as Senior Vice President and Chief
Financial Officer of Total Energy Services, Inc., an oilfield services and
products company. From 1985 until 1993, Mr. Morrow was Chief Financial Officer
of The Western Company of North America, an oilfield services company. Mr.
Morrow received his bachelor's degree in economics from De Pauw University in
1971 and his MBA from the University of Michigan in 1973.

     Mr. Mackewn joined PGS as Technology Director of PGS Nopec in 1993,
transferred to PGS Exploration in 1996 as Managing Director of PGS Exploration
UK Ltd., was named President -- Exploration EAME in November 1999 and was named
President -- PGS Geophysical Services in May 2001. Mr. Mackewn graduated with an
honors degree in physics from the University of Southampton in 1969.

     Mr. Gisvold joined PGS in December 1997 as part of PGS' acquisition of the
FPSO operations (Golar-Nor Offshore) of Awilco ASA. He was appointed
President -- PGS Production in June 2000, prior to which time he served as a
Senior Vice President responsible for strategic development of FPSO activities.
From 1983 through December 1997, Mr. Gisvold was Chief Executive Officer of the
NFDS drilling company Golar-Nor Offshore, where he was responsible for the
technical and commercial development of the FPSO group. From 1981 to 1983, Mr.
Gisvold worked with Volvo of Sweden. From 1971 through 1981, Mr. Gisvold was
responsible for developing and running the MARINTEK laboratories in Trondheim,
Norway. Mr. Gisvold received both an MSc and a PhD in naval architecture and
marine engineering from the Technical University of Norway in 1967 and 1971,
respectively.

     Mr. Berteussen was appointed Senior Vice President -- Reservoir Technology
in November 1999, having served as President of PGS Reservoir AS since 1995.
From 1987 to 1995, Mr. Berteussen was President of Read Well Services. From 1982
to 1987, Mr. Berteussen worked at Saga Petroleum,

                                        53
<PAGE>

ultimately reaching the position of Senior Manager, Geophysics. From 1971 to
1981, Mr. Berteussen was an assistant professor at Oslo University and,
beginning in 1985, has served as an adjunct professor at the University of
Tromso in Norway. From 1972 to 1976, Mr. Berteussen was a research scientist
with Norwegian Seismic Array (NORSAR). Mr. Berteussen received a PhD in
seismology from the University of Oslo in 1976 and an MS in geophysics from
Bergen University in 1972.

     Mr. Harlan joined PGS in August 1996 as the Vice President -- Chief
Accounting and Administrative Officer. Prior to joining PGS, Mr. Harlan was the
Controller of Air Liquide America Corporation, the US subsidiary of L'Air
Liquide, from 1995 to 1996. From 1991 to 1994, Mr. Harlan served in Jakarta,
Indonesia as the Chief Financial Officer of the Indonesian Operations of Huffco,
a Houston-based oil and gas exploration and production company. Prior to joining
Huffco, Mr. Harlan, a certified public accountant, was employed by KPMG Peat
Marwick from 1988 to 1991 and by Arthur Andersen from 1983 to 1988. Mr. Harlan
received his bachelor's and master's degrees of accountancy from the University
of Mississippi in 1981 and 1983, respectively.

     Mr. Haavardsen has been general counsel and secretary of PGS since 1992.
Mr. Haavardsen served as senior vice president of Foinco Invest A.S. from 1989
to 1991, as general counsel and vice president of Geco from 1987 to 1989 and as
legal director of Aspelin-Stormbull AS from 1975 to 1986. Mr. Haavardsen
received a law degree from Oslo University in 1967, and an AMP from Harvard
Business School in 1983.

SHARE OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS

     As of December 31, 2001, the total number of our shares and ADSs,
beneficially held by our directors and executive officers as a group (13
persons) was 1,597,540, representing approximately 2% of our outstanding shares.
This amount includes 1,254,000 shares that could be acquired upon the exercise
of options vested as of March 1, 2002.

COMPENSATION OF DIRECTORS AND EXECUTIVE OFFICERS

     For the year ended December 31, 2001, the aggregate amount we paid for
compensation to our directors and executive officers as a group (13 persons) for
services in all capacities was approximately $3.8 million (exclusive of any
compensation attributable to any exercises of stock options). Mr. Michaelsen,
our chief executive officer, received compensation for services to us during
2001 (exclusive of any compensation attributable to any exercises of stock
options) of approximately $1.2 million. The aggregate benefits that had accrued
to our executive officers as a group (8 persons) under our various defined
benefit plans for the year ended December 31, 2001 was $1.1 million.

     As of January 1, 2000, we entered into a deferred compensation agreement
with one of our directors providing for director benefits upon termination of
his directorship. The benefits accrue in the amount of $100,000 for each year of
service, plus interest. As of December 31, 2001, approximately $200,000 in
benefits had ratably accrued under this program. In the event of a change of
control of our company or the director's death, the director or his
beneficiaries will receive a lump sum payment of all unpaid amounts credited to
his deferred compensation account.

     We have established a discretionary incentive bonus plan designed primarily
to compensate designated members of our senior management when we achieve
specified annual performance-related goals. Participants in the plan are
designated by the compensation committee of our board of directors. Performance
goals and related award schedules for award periods may be established under the
plan periodically and generally cannot be changed once established. Awards that
accrue for each year are contingent until paid, unless earlier vested due to a
change in control of our company, plan termination or a participant's
involuntary termination of employment without cause, including by reason of
death or disability. Unless earlier vested, any awards that accrue during an
award period are forfeited by a participant who is no longer employed by us or
our subsidiaries on the date award payments are made. Payment of accrued awards
is deferred until after the end of the award period and is made in a cash lump

                                        54
<PAGE>

sum. The maximum individual award potentially payable with respect to any year
is 100% of a participant's base salary (for 2001, $950,000 for Mr. Michaelsen).
The compensation committee has established a base award period for the plan
covering the three years from 1996 to 1999 with a granted extension period
through 2001, with annual awards during such periods accruing based in part
(75%) on targeted operating profit levels and increases in our earnings per
share. The remaining 25% of any annual award is granted at the discretion of the
compensation committee.

     As of December 31, 2001, our directors and executive officers as a group
(13 persons) held options for 2,941,000 shares. As of that date, Mr. Michaelsen
individually held options as shown in the table below. No other directors or
executive officers individually held options equivalent to (or greater than) 1%
of our outstanding shares at December 31, 2001; their aggregate holdings are
shown in the table below. We have translated the NOK amounts in the table solely
for convenience into US dollars at the noon buying rate on December 31, 2001
($1.00 = NOK 8.97).

<Table>
<Caption>
                                                                          NUMBER OF    EXERCISE PRICE
                                                                         OUTSTANDING   ---------------
NAME                                             EXERCISE DATES            OPTIONS      NOK       $
----                                       ---------------------------   -----------   ------   ------
<S>                                        <C>                           <C>           <C>      <C>
Reidar Michaelsen........................  July 1, 2000 - July 1, 2002     720,000     162.0    18.06
                                           July 1, 2003 - July 1, 2006     900,000     133.0    14.83
Remaining directors and executive
  officers...............................  July 1, 2000 - July 1, 2002     226,000     162.0    18.06
                                           July 1, 2000 - July 1, 2002     135,000     137.5    15.33
                                           July 1, 2001 - July 1, 2003      40,000     229.5    25.59
                                           July 1, 2001 - July 1, 2003     133,000     111.0    12.37
                                           July 1, 2002 - July 1, 2004      40,000     128.5    14.33
                                           July 1, 2002 - July 1, 2004      55,000     131.5    14.66
                                           July 1, 2003 - July 1, 2006     100,000     160.0    17.84
                                           July 1, 2003 - July 1, 2006     492,000     150.0    16.72
                                           July 1, 2004 - July 1, 2007     100,000     103.0    11.48
</Table>

     Please read notes 16 and 18 of the notes to our financial statements in
Item 18 of this annual report for additional information regarding our share
option and retirement plans.

EMPLOYEES

     At December 31, 2001, 2000 and 1999, we employed approximately 5,100, 4,200
and 4,100 full-time personnel, respectively. The mix between full-time personnel
employed solely in our geophysical services group and our production services
group for the year ended December 31, 2001 was 48% and 48%, respectively, which
was consistent with the prior year mix. Our remaining employees provide services
across the two segments of our organization. We have not experienced any
material work stoppages related to union activities and consider our relations
with our employees to be good.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

     Based on an amendment to Schedule 13G filed with the Securities and
Exchange Commission on January 23, 2002 by Mellon Financial Corporation, on
behalf of itself and a number of its subsidiaries, Mellon, through various
subsidiaries, beneficially owns 11,645,410 shares, or 11.3% of the outstanding
shares. Mellon does not have voting rights different from those of any other
shareholders of PGS. To our knowledge, no other person or group beneficially
owns 5% or more of our outstanding shares.

     At December 31, 2001, we were party to a definitive agreement to combine
with Veritas. For additional information about this transaction, please read
"Information on the Company -- Recent Developments -- Combination with Veritas"
in Item 4 and note 3 of the notes to our financial statements in Item 18 of this
annual report.

     As of December 31, 2001, there were 133 record holders of ADSs representing
46,762,867 shares, 116 of which had registered addresses in the United States.
These 116 United States record holders held ADSs

                                        55
<PAGE>

representing 46,750,453 shares, which represented approximately 45% 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, 2001, there were
103,345,987 shares outstanding (including shares represented by ADSs) held by
5,905 record holders, of which 76 had registered addresses in the United States
and 5,484 had registered addresses in Norway. The United States holdings
represented 56,810,791 shares, or approximately 55% of the total number of our
shares outstanding as of that date. For this purpose, Citibank, 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 30,951,046 shares, or approximately 30% of the
total number of our shares outstanding as of that date.

     Please read note 19 of the notes to our financial statements in Item 18 of
this annual report for information regarding our related party transactions.

ITEM 8. FINANCIAL INFORMATION

FINANCIAL STATEMENTS

     Please read Item 18 of this annual report.

LEGAL PROCEEDINGS

     From time to time, we are involved in or threatened with various legal
proceedings arising in the ordinary course of business. Our management does not
believe that we are engaged in, or have recently been engaged in, any legal or
arbitration proceedings which 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.

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-kind are payable only out of:

     - 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

        - 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 the balance sheet, amounts to less than 10% of the balance sheet,
or dividends in excess of an amount that is

                                        56
<PAGE>

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. Additionally, the terms of our debt agreements impose limitations on
the payment of dividends. We do not currently intend to declare or pay
dividends, but intend to reinvest any profit.

SIGNIFICANT CHANGES

     Except as disclosed in "Information on the Company -- Recent
Developments -- Combination with Veritas" and "-- Sale of Atlantis" in Item 4,
"Operating and Financial Review and Prospects -- Financial Condition -- Capital
Resources and Liquidity" in Item 5, and notes 3 and 10 of the notes to our
financial statements in Item 18 of this annual report, no significant changes
have occurred since the date of our annual financial statements.

ITEM 9. THE OFFER AND LISTING

LISTING DETAILS

     Our 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 have not been publicly traded outside Norway. Each ADS represents one share.
Citibank, N.A. serves as the depositary for the ADSs. Our ADSs are listed on the
New York Stock Exchange and trade on that exchange under the symbol "PGO."

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>
1997........................................................  $38.41   $19.00
1998........................................................   37.38    11.81
1999........................................................   24.19    11.19
2000........................................................   19.56    10.00
2001........................................................   14.63     5.00
2000
  First Quarter.............................................   19.56    13.69
  Second Quarter............................................   19.56    14.88
  Third Quarter.............................................   19.31    16.00
  Fourth Quarter............................................   17.13    10.00
2001
  First Quarter.............................................   14.63     8.05
  Second Quarter............................................   12.89     8.20
  Third Quarter.............................................   10.95     5.49
  Fourth Quarter............................................    8.11     5.00
2002
  First Quarter.............................................    7.89     4.81
Last Six Months
     April..................................................    6.89     6.11
     March..................................................    6.51     4.81
     February...............................................    6.95     5.43
     January................................................    7.89     6.44
     December...............................................    8.11     6.50
     November...............................................    6.71     5.00
</Table>

                                        57
<PAGE>

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.

<Table>
<Caption>
                                                                PRICE PER SHARE
                                                              -------------------
CALENDAR PERIOD                                                 HIGH       LOW
---------------                                               --------   --------
<S>                                                           <C>        <C>
1997........................................................  NOK268.5   NOK124.5
1998........................................................     282.0       91.5
1999........................................................     185.5       84.0
2000........................................................     174.0       91.5
2001........................................................     124.5       44.0
2000
  First Quarter.............................................     160.0      109.5
  Second Quarter............................................     172.0      127.0
  Third Quarter.............................................     174.0      141.5
  Fourth Quarter............................................     159.0       91.5
2001
  First Quarter.............................................     124.5       73.0
  Second Quarter............................................     116.0       76.0
  Third Quarter.............................................      97.5       44.0
  Fourth Quarter............................................      69.5       44.0
2002
  First Quarter.............................................      70.0       41.0
  Last Six Months
     April..................................................      59.0       53.5
     March..................................................      53.5       41.0
     February...............................................      65.0       49.5
     January................................................      70.0       57.0
     December...............................................      69.5       57.5
     November...............................................      57.0       44.5
</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
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'

                                        58
<PAGE>

meeting, whether or not holders of the share capital are entitled to vote. In
some cases, a stricter voting requirement may apply.

     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 either:

     - a majority of our total outstanding voting shares or

     - more than two-thirds of the votes cast and more than two-thirds of the
       share capital represented at the meeting

     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. 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.

     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 and distribution of cash dividends out of our
annual profit, any matter that may be raised at an annual general meeting may
also be raised at an extraordinary general meeting.

  RESTRICTIONS ON OWNERSHIP OF SHARES

     At present, there is no limitation on ownership of shares by persons who
are not Norwegian. The Norwegian 1994 Act on Control of Business Acquisitions
requires any holder of shares or group of holders acting in concert, regardless
of nationality, to notify the Norwegian government upon the acquisition of
shares that would cause that holder's or group's aggregate holdings either:

     - to exceed a threshold of 33 1/3% of the total outstanding shares or

     - to reach a threshold of 50% or 66 2/3% of the total outstanding shares

For purposes of these determinations, shares include ADSs.

                                        59
<PAGE>

     Any acquisition of shares or ADSs exceeding or reaching the thresholds
described in the previous paragraph would be subject to a waiting period. During
the waiting period, Norwegian governmental authorities could request further
information, disapprove the acquisition or impose conditions aimed at
safeguarding the public interest. During the waiting period, the acquiror is
restricted from exercising its rights as a shareholder other than receiving
dividends and exercising preemptive rights. If the waiting period expires and no
official action occurs, the acquisition could go forward without condition.

  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 and
authorized securities brokers in Norway 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.

     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.

  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 1/10, 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. Our
shareholders also must approve by the same vote the issuance of loans
convertible into

                                        60
<PAGE>

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

     - 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 US holders will not be
able to exercise their preemptive rights and would be required to sell them to
Norwegian persons or other non-US holders to realize the value of the rights.

     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

     - 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

     Under Norwegian law, we can pay dividends only once a year in cash or in
kind as a distribution of our annual profit and the annual profits of our
Norwegian subsidiaries. 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 kind are payable only out of:

     - 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

        - any part of the annual profit that, according to law or our articles
          of association and the articles of our Norwegian subsidiaries, must be
          allocated to restricted funds

                                        61
<PAGE>

Neither we nor our Norwegian subsidiaries can declare dividends if the equity,
according to the balance sheet, amounts to less than 10% of the balance sheet.
In addition, neither we nor they can declare 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.

     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.

  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.

  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 or 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. The offer may not be
conditional and is subject to approval by the Oslo Stock Exchange before
submission to the shareholders. 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 additional shares at a higher price after
exceeding the 40% threshold but prior to the expiration of the 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. In addition, the Oslo Stock Exchange may
impose a daily fine upon a shareholder who fails to make the required offer.

     In addition to these mandatory bid requirements under Norwegian statutory
law, our articles of association require an acquiror of shares and/or ADSs
representing more than one-third of the outstanding voting rights, but less than
the 40% threshold for a mandatory bid requirement, to offer to purchase the

                                        62
<PAGE>

remaining outstanding shares. Subject to the requirement that our board notify
the acquiror, our board of directors may withhold approval of the acquisition of
shares and/or ADSs to determine that the acquiror has complied with the
mandatory bid requirements of the articles of association.

     If an acquiror has not complied with these requirements, our board of
directors may disapprove the acquisition of shares and/or ADSs. If the board of
directors reasonably determines that, for any particular acquisition of shares
and/or ADSs by an acquiror, the mandatory bid requirements in our articles of
association are not in our interest or the interest of our shareholders, the
board may exempt that acquiror from such requirements. Except as we have
described above, the rules generally regarding mandatory bids under applicable
Norwegian law at the relevant time will apply to the application of the
mandatory bid requirements of our articles of association.

     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.

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.

     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
United States 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 United
States federal income taxation on a net income basis for ADRs and shares and who
are not residents of Norway ("US 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 US
Holders are advised to consult their own tax advisors about the United States
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 United States 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).

     For United States and Norwegian tax purposes, US 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 United States
federal income tax consequences discussed below apply equally to US Holders of
ADRs and US Holders of shares.

                                        63
<PAGE>

  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
US 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. US
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.

     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 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 US Holder will be treated as taxable domestic dividend
income in Norway, subject to the provisions of the Convention, where applicable.

     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 US Holder for United States federal income tax
purposes as ordinary dividend income. In the case of a US 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 US Internal Revenue Code
of 1986, as amended (the "Code"). The amount of dividend distribution for tax
purposes will equal the US 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 US
dollars of the Norwegian kroner received in a distribution, US Holders of ADRs
generally will recognize gain or loss for United States federal income tax
purposes equal to the difference, if any, between such US dollars and the US
dollar value of such Norwegian kroner on the date of the distribution. Such gain
or loss will be treated as ordinary income or loss.

     Norwegian taxes imposed on dividend distributions on our shares or ADSs
generally will be eligible for credit against the US Holder's United States
federal income taxes. The amount of the Norwegian taxes eligible for this
foreign tax credit 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, translated into US dollars at the exchange rate in effect
on the date the taxes originally were paid. Under the foreign tax credit
limitations of the Code, the foreign tax credit can offset United States federal
income taxes imposed on foreign-source income but not on United States-source
income. In addition, foreign taxes imposed on income in certain categories
specified in the Code may only be used to offset United States taxes on income
in the same category. Subject to the special rule 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 US Holder's circumstances.

     The Code contains a provision that could, in certain circumstances, cause a
portion of the dividends we pay to be treated as United States-source income.
Even if that provision applied to dividends we pay to a US Holder, because of
the source rules contained in the Convention, no portion of such a dividend
would be recharacterized as United States-source income if the US Holder
includes the dividend as a separate category of income for purposes of the
foreign tax credit limitation.
                                        64
<PAGE>

  TAXATION OF DISPOSITIONS

     A US 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.

     A US Holder will recognize capital gain or loss for United States 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). Any such gain
or loss will generally be United States-source income or loss.

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

  US BACKUP WITHHOLDING

     Certain payments, including certain dividends and proceeds from sales of
stock, may be subject to United States "backup withholding" at the current 30%
rate if the recipient of such a payment fails to furnish to the payor certain
information, including the recipient's taxpayer identification number, or
otherwise fails to establish an exemption from withholding. Any amounts so
withheld would be allowed as a credit against the recipient's United States
federal income tax liability for the year. Dividends we pay to a US Holder
generally would be subject to these backup withholding rules.

  NORWEGIAN TRANSFER TAX

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

  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

     US 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 annual report that we
have filed with the SEC.

                                        65
<PAGE>

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Our earnings and cash flows are subject to fluctuations due to changes in
foreign currency exchange rates. We periodically enter into forward foreign
currency exchange contracts and option contracts to hedge firm commitments but
not for speculative or trading purposes. Our business contracts generally
provide for payment in US dollars, and we do not maintain significant foreign
currency cash balances. Our tax equalization swap contracts carried weighted
average exchange rate floors of 7.7 NOK to the US dollar and 7.4 NOK to the US
dollar, respectively at December 31, 2001 and 2000. Under each tax equalization
swap contract, if the NOK to US dollar exchange rate at any settlement date is
less than the contract's exchange rate floor, we will neither incur a liability
nor accrue a benefit for the exchange rate differential below the floor. At
December 31, 2001, after the determination of the December 2001 interim
settlement, the outstanding aggregate notional value of the tax equalization
swap contracts was $492.8 million and the base exchange rate on the contracts
was reset to approximately 9.0 NOK to the US dollar. The December 2002 interim
settlement will be measured as the difference between this base exchange rate
and the then current exchange rate, subject to the exchange rate floor, applied
to the outstanding aggregate notional value of the tax equalization swap
contracts. Accordingly, we will incur a liability (payable in NOK) if the NOK to
US dollar exchange rate exceeds the base exchange rate of 9.0 NOK to the US
dollar, or we will accrue a benefit (receivable in NOK) if such exchange rate is
less than this base exchange rate (subject to the exchange rate floor). Please
read notes 2 and 17 of the notes to our financial statements in Item 18 of this
annual report and "Operating and Financial Review and Prospects -- Currency
Fluctuations" in Item 5 of this annual report for additional information
regarding our tax equalization swaps.

     In April 2002, we terminated three tax equalization swap contracts with
aggregate notional values of $160.0 million. We did not recognize any
significant impact in our results of operations as a result of the termination.

     Our earnings and cash flows are also exposed to changes in interest rates
on our long-term debt obligations. Please read notes 10 and 11 of the notes to
our financial statements in Item 18 of this annual report for additional
information regarding the level and maturity profiles of our borrowings and the
types of financial instruments used. We present below the weighted average
interest rate for the scheduled maturities of our fixed rate long-term debt
obligations as of December 31, 2001 and 2000 (in thousands of dollars):

<Table>
<Caption>
                                                                                                                   ESTIMATED
                             2001      2002       2003      2004      2005      2006     THEREAFTER     TOTAL      FAIR VALUE
                            -------   -------   --------   -------   -------   -------   ----------   ----------   ----------
<S>                         <C>       <C>       <C>        <C>       <C>       <C>       <C>          <C>          <C>
AS OF DECEMBER 31, 2000
Fixed Rate Debt:
  Amount Due.............   $11,090   $11,595   $258,737   $10,200   $10,990   $11,920   $1,271,112   $1,585,644   $1,501,953
  Weighted Average
    Interest Rate........       8.3%      8.3%       6.3%      8.3%      8.3%      8.3%         7.4%         7.2%          --
AS OF DECEMBER 31, 2001
Fixed Rate Debt:
  Amount Due.............   $    --   $12,240   $258,959   $10,200   $10,990   $11,920   $1,271,503   $1,575,812   $1,356,350
  Weighted Average
    Interest Rate........        --%      8.5%       6.3%      8.3%      8.3%      8.3%         7.4%         7.2%          --
</Table>

     Our fixed rate debt includes Norwegian kroner-denominated debt totaling
$0.7 million and $5.8 million at December 31, 2001 and 2000, respectively.

     Our $141.0 million of trust preferred securities carried a 9.6% interest
rate and a $136.5 million fair value at December 31, 2001.

     Our $225.0 million unsecured floating-rate senior notes matured in March
2002; at December 31, 2001 these notes carried a 3.6% interest rate and had a
fair value of $224.8 million. During 2001, we utilized our unsecured five-year
$430.0 million revolving bank credit facility that bears interest at a
LIBOR-based rate; at December 31, 2001, our outstanding balance on this facility
of $340.0 million carried a 2.7% weighted average interest rate and a fair value
approximately equal to its carrying value.

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

     Not applicable.

                                        66
<PAGE>

                                    PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

     None.

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

     None.

                                    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 Public Accountants -- Arthur Andersen
  LLP.......................................................  F-1
Report of Independent Accountants -- PricewaterhouseCoopers
  LLP.......................................................  F-2
Consolidated Balance Sheets as of December 31, 2001 and
  2000......................................................  F-3
Consolidated Statements of Operations for the years ended
  December 31, 2001, 2000 and 1999..........................  F-4
Consolidated Statements of Cash Flows for the years ended
  December 31, 2001, 2000 and 1999..........................  F-5
Consolidated Statements of Changes in Shareholders' Equity
  for the years ended December 31, 2001, 2000 and 1999......  F-6
Notes to Consolidated Financial Statements..................  F-7
</Table>

     We specifically incorporate by reference in response to this item the
auditors' reports, the consolidated financial statements and the notes to the
consolidated financial statements appearing on pages F-1 through F-41.

ITEM 19. EXHIBITS

<Table>
<Caption>
         NUMBER
         ------
<C>                      <S>
           1.1           -- Articles of Association, as amended (English translation)
           2.1           -- Deposit Agreement, dated as of May 25, 1993, among
                            Petroleum Geo-Services ASA (the "Company"), Citibank,
                            N.A., as depositary (the "Depositary"), and all holders
                            from time to time of American Depositary Receipts issued
                            thereunder (incorporated by reference to Exhibit (a)(1)
                            of Post-Effective Amendment No. 1 to the Company's
                            Registration Statement on Form F-6 (Registration No.
                            33-61500))
           2.2           -- First Amendment to Deposit Agreement, dated as of April
                            24, 1997, among the Company, the Depositary and all
                            holders from time to time of American Depositary Receipts
                            issued thereunder (incorporated by reference to Exhibit
                            (a)(2) of the Company's Registration Statement on Form
                            F-6 (Registration No. 333-10856))
           2.3           -- Form of American Depositary Receipt (included in Exhibit
                            2.2)
</Table>

                                        67
<PAGE>

<Table>
<Caption>
         NUMBER
         ------
<C>                      <S>
           2.4           -- Certificate of Trust of PGS Trust I (the "Trust")
                            (incorporated by reference to Exhibit 4.10.1 of the
                            Registration Statement of the Company and the Trust on
                            Form F-3 (Registration Nos. 333-10348 and 333-10348-01))
           2.5           -- Amended and Restated Declaration of Trust of the Trust,
                            dated as of June 22, 1999, among the trustees of the
                            Trust named therein, the Company, as Sponsor, and the
                            holders from time to time of preferred undivided
                            beneficial interests in the assets of the Trust
                            (incorporated by reference to Exhibit 1 of the Company's
                            Report on Form 6-K dated July 12, 1999 (SEC File No.
                            1-14614))
           2.6           -- Indenture, dated as of June 22, 1999, between the Company
                            and Chase Bank of Texas, National Association, as
                            Trustee, in respect of junior subordinated debentures of
                            the Company (incorporated by reference to Exhibit 2 of
                            the Company's Report on Form 6-K dated July 12, 1999 (SEC
                            File No. 1-14614))
           2.7           -- First Supplemental Indenture, dated as of June 22, 1999,
                            between the Company and Chase Bank of Texas, National
                            Association, as Trustee, in respect of 9 5/8% Junior
                            Subordinated Debentures due 2039 of the Company
                            (incorporated by reference to Exhibit 3 of the Company's
                            Report on Form 6-K dated July 12, 1999 (SEC File No.
                            1-14614))
           2.8           -- Form of 9 5/8% Junior Subordinated Debenture due 2039
                            (included in Exhibit 2.7)
           2.9           -- Guarantee Agreement, dated as of June 22, 1999, between
                            the Company and Chase Bank of Texas, National
                            Association, as Guarantee Trustee (incorporated by
                            reference to Exhibit 4 of the Company's Report on Form
                            6-K dated July 12, 1999 (SEC File No. 1-14614))
           2.10          -- Form of Preferred Security (included in Exhibit 2.5)
           2.11          -- Indenture, dated as of April 1, 1998, between the Company
                            and Chase Bank of Texas, National Association, as
                            trustee, in respect of senior debt securities
                            (incorporated by reference to exhibit 2.12 of the
                            Company's Annual Report on Form 20-F for the year ended
                            December 31, 1997 (SEC File No. 1-14614))
           2.12          -- First Supplemental Indenture, dated as of April 1, 1998,
                            between the Company and Chase Bank of Texas, National
                            Association, as trustee, in respect of 6 5/8% Senior
                            Notes due 2008 and 7 1/8% Senior Notes due 2028
                            (incorporated by reference to exhibit 2.13 of the
                            Company's Annual Report on Form 20-F for the year ended
                            December 31, 1997 (SEC File No. 1-14614))
           2.13          -- Revolving Credit Agreement dated as of September 4, 1998
                            among the Company, Chase Manhattan PLC, as arranger,
                            Chase Manhattan International Limited, as agent, and the
                            financial institutions listed therein (incorporated by
                            reference to exhibit 2.5 of the Company's Annual Report
                            on Form 20-F for the year ended December 31, 1998 (SEC
                            File No. 1-14614))
                            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.
           4.1           -- Employment agreement dated April 27, 2000 between the
                            Company and Michael Mathews (incorporated by reference to
                            Exhibit 4.1 of the Company's Annual Report on Form 20-F
                            for the year ended December 31, 2000 (File No. 1-14614)
                            (the "Form 20-F"))
</Table>

                                        68
<PAGE>

<Table>
<Caption>
         NUMBER
         ------
<C>                      <S>
           4.2           -- Employment agreement dated July 31, 1997 between the
                            Company and Reidar Michaelsen (incorporated by reference
                            to Exhibit 4.2 of the Form 20-F)
           4.3           -- Petroleum Geo-Services ASA Executive Pension Scheme dated
                            August 29, 1996 (incorporated by reference to Exhibit
                            4.13 of the Form 20-F)
           4.4           -- Petroleum Geo-Services ASA 2000 -- Incentive Share Option
                            Plan dated June 23, 2000 (incorporated by reference to
                            Exhibit 4.14 of the Form 20-F)
           4.5           -- Petroleum Geo-Services ASA Non-Employee Director Stock
                            Option Plan dated January 1, 2000 (incorporated by
                            reference to Exhibit 4.15 of the Form 20-F)
           4.6           -- Framework Agreement, dated as of April 26, 2001, among
                            Multi-Klient Invest AS, the Company, PGS Multi-Client
                            Seismic Limited, Compass Finrec P Limited, Westdeutsche
                            Landesbank Girozentrale and Compass Holdings Limited
                            (incorporated by reference to Exhibit 4.16 of the Form
                            20-F)
           4.7           -- Servicing Agreement, dated as of April 26, 2001, among
                            Multi-Klient Invest AS, the Company, PGS Multi-Client
                            Seismic Limited, Compass Finrec P Limited, Westdeutsche
                            Landesbank Girozentrale and Compass Holdings Limited
                            (incorporated by reference to Exhibit 4.17 of the Form
                            20-F)
           4.8           -- Jersey License Agreement, dated as of April 26, 2001,
                            among Multi-Klient Invest AS, the Company, PGS
                            Multi-Client Seismic Limited, Compass Finrec P Limited,
                            Westdeutsche Landesbank Girozentrale and Compass Holdings
                            Limited (incorporated by reference to Exhibit 4.18 of the
                            Form 20-F)
           8             -- Subsidiaries (included in Item 4 of the annual report)
          10.1           -- Consent of Arthur Andersen LLP
          10.2           -- Consent of PricewaterhouseCoopers LLP
          99.1           -- Letter to the Securities and Exchange Commission
                            regarding Arthur Andersen LLP
</Table>

                                        69
<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

Date: May 22, 2002
                                            By:    /s/ REIDAR MICHAELSEN
                                              ----------------------------------
                                                      Reidar Michaelsen
                                                      Chairman and Chief
                                                      Executive Officer

                                            By: /s/ J. CHRISTOPHER BOSWELL
                                             -----------------------------------
                                                   J. Christopher Boswell
                                                  Senior Vice President and
                                                   Chief Financial Officer

                                            By:    /s/ WILLIAM E. HARLAN
                                              ----------------------------------
                                                      William E. Harlan
                                               Vice President, Chief Accounting
                                                  and Administrative Officer

                                        70
<PAGE>

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Shareholders of
PETROLEUM GEO-SERVICES ASA:

We have audited the accompanying consolidated balance sheet of Petroleum
Geo-Services ASA and subsidiaries (the "Company") as of December 31, 2001 and
the related statements of operations, cash flows and shareholders' equity for
the year ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

We conducted our audit in accordance with auditing standards generally accepted
in the 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 audit provides 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 the Company as of December 31,
2001 and the results of their operations and their cash flows for the year ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.

                                          ARTHUR ANDERSEN LLP

Houston, Texas
May 2, 2002 (except with respect
to the matter discussed in Note 10,
as to which the date is May 16, 2002)

                                       F-1
<PAGE>

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of
PETROLEUM GEO-SERVICES ASA

In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, of cash flows and of changes in
shareholders' equity present fairly, in all material respects, the financial
position of Petroleum Geo-Services ASA and its subsidiaries at December 31, 2000
and the results of their operations and their cash flows for each of the two
years in the period ended December 31, 2000 in conformity with accounting
principles generally accepted in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
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, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

As discussed in Notes 1 and 24, the Company restated its 1999 and 2000 financial
statements.

PricewaterhouseCoopers LLP

Houston, Texas
March 12, 2001, except as to the last five
paragraphs of Note 11, which are as of
April 30, 2001, and as to the third paragraph
of Note 1 and Note 24, which are as of
May 10, 2002

                                       F-2
<PAGE>

                          CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
                                                                     DECEMBER 31,
                                                              --------------------------
                                                                 2001           2000
                                                              -----------    -----------
                                                              (IN THOUSANDS OF DOLLARS,
                                                                EXCEPT FOR SHARE DATA)
                                                                                 (AS
                                                                              RESTATED,
                                                                              NOTE 24)
<S>                                                           <C>            <C>
                                         ASSETS
Cash and cash equivalents...................................  $  110,909     $  145,215
Accounts receivable, net....................................     254,177        242,751
Oil and gas assets..........................................     171,041        113,890
Other current assets, net...................................      99,959         88,995
                                                              ----------     ----------
          Total current assets..............................     636,086        590,851
Multi-client library, net...................................     918,072        848,720
Property and equipment, net.................................   2,282,241      2,251,943
Goodwill, net...............................................     215,291        253,861
Other long-term assets, net.................................     251,116        333,331
                                                              ----------     ----------
          Total assets......................................  $4,302,806     $4,278,706
                                                              ==========     ==========

                          LIABILITIES AND SHAREHOLDERS' EQUITY

Short-term debt and current portion of long-term debt
  and capital lease obligations.............................  $  267,657     $   23,892
Accounts payable............................................      76,859        105,614
Accrued expenses............................................     226,127        297,607
Income taxes payable........................................      16,944         12,263
                                                              ----------     ----------
          Total current liabilities.........................     587,587        439,376
Long-term debt..............................................   1,903,571      2,159,421
Long-term capital lease obligations.........................      41,683         12,560
Other long-term liabilities.................................      25,355         81,061
Deferred tax liabilities....................................      78,575         96,260
                                                              ----------     ----------
          Total liabilities.................................   2,636,771      2,788,678
                                                              ----------     ----------
Commitments and contingencies (Note 12)
Guaranteed preferred beneficial interest in PGS junior
  subordinated debt securities (Note 11)....................     141,000        140,050
Mandatorily redeemable cumulative preferred subsidiary
  securities related to multi-client library securitization
  (Note 11).................................................     163,588             --
Shareholders' equity
  Common stock, par value NOK 5; authorized 135,400,587
     shares; issued and outstanding 103,345,987 shares at
     December 31, 2001 and 102,347,987 shares at December
     31, 2000...............................................      71,089         70,542
  Additional paid-in capital................................   1,225,115      1,215,884
  Retained earnings.........................................      98,863         94,410
  Accumulated other comprehensive loss......................     (33,620)       (30,858)
                                                              ----------     ----------
          Total shareholders' equity........................   1,361,447      1,349,978
                                                              ----------     ----------
          Total liabilities and shareholders' equity........  $4,302,806     $4,278,706
                                                              ==========     ==========
</Table>

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

                     CONSOLIDATED STATEMENTS OF OPERATIONS

<Table>
<Caption>
                                                                   YEARS ENDED DECEMBER 31,
                                                      --------------------------------------------------
                                                           2001              2000              1999
                                                      ---------------   ---------------   --------------
                                                       (IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
                                                                         (AS RESTATED,    (AS RESTATED,
                                                                           NOTE 24)          NOTE 24)
<S>                                                   <C>               <C>               <C>
Revenue.............................................   $  1,052,628      $    913,482      $   788,160
                                                       ------------      ------------      -----------
Cost of sales.......................................        535,999           432,457          333,060
Depreciation and amortization.......................        334,506           263,589          238,576
Research and technology costs.......................          3,752             6,677           15,859
Selling, general and administrative costs...........         78,305            76,473           71,738
Unusual items (Note 23).............................       (105,912)          365,780           89,855
                                                       ------------      ------------      -----------
          Total operating expenses..................        846,650         1,144,976          749,088
                                                       ------------      ------------      -----------
Operating profit (loss).............................        205,978          (231,494)          39,072
Income (loss) from equity investments...............           (491)           61,151           (4,935)
Financial expense, net..............................       (143,179)         (134,599)         (95,969)
Other expense, net..................................        (22,052)          (32,774)          (9,144)
                                                       ------------      ------------      -----------
Income (loss) before income taxes...................         40,256          (337,716)         (70,976)
Provision (benefit) for income taxes................         35,803          (132,756)         (57,137)
                                                       ------------      ------------      -----------
Income (loss) before cumulative effect of accounting
  change............................................          4,453          (204,960)         (13,839)
Cumulative effect of accounting change, net of
  tax...............................................             --            (6,555)         (19,977)
                                                       ------------      ------------      -----------
          Net income (loss).........................   $      4,453      $   (211,515)     $   (33,816)
                                                       ============      ============      ===========
Basic income (loss) per share before cumulative
  effect of accounting change.......................   $       0.04      $      (2.01)     $     (0.15)
Cumulative effect of accounting change, net of
  tax...............................................             --             (0.06)           (0.21)
                                                       ------------      ------------      -----------
Basic income (loss) per share.......................   $       0.04      $      (2.07)     $     (0.36)
                                                       ============      ============      ===========
Diluted income (loss) per share before cumulative
  effect of accounting change.......................   $       0.04      $      (2.01)     $     (0.15)
Cumulative effect of accounting change, net of
  tax...............................................             --             (0.06)           (0.21)
                                                       ------------      ------------      -----------
Diluted net income (loss) per share.................   $       0.04      $      (2.07)     $     (0.36)
                                                       ============      ============      ===========
Basic shares outstanding............................    102,768,283       102,020,830       94,767,967
                                                       ============      ============      ===========
Diluted shares outstanding..........................    102,788,055       102,020,830       94,767,967
                                                       ============      ============      ===========
</Table>

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

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
                                                                     YEARS ENDED DECEMBER 31,
                                                             -----------------------------------------
                                                               2001          2000            1999
                                                             ---------   -------------   -------------
                                                                     (IN THOUSANDS OF DOLLARS)
                                                                         (AS RESTATED,   (AS RESTATED,
                                                                           NOTE 24)        NOTE 24)
<S>                                                          <C>         <C>             <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income (loss)........................................  $   4,453     $(211,515)     $   (33,816)
  Adjustments to reconcile net income (loss) to net cash
    provided by operating activities:
    Depreciation and amortization charged to expense.......    334,506       263,589          238,576
    Non-cash charges.......................................    (97,027)      321,070           83,805
    Provision (benefit) for deferred income taxes..........     22,114      (141,000)         (68,717)
    Changes in current assets and current liabilities......    (74,721)      (72,636)            (313)
    Loss on sale of assets.................................        294           199            3,256
    Other items............................................     22,083        (1,550)         (22,113)
                                                             ---------     ---------      -----------
         Net cash provided by operating activities.........    211,702       158,157          200,678
                                                             ---------     ---------      -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Investment in multi-client library.......................   (230,166)     (264,541)        (338,718)
  Capital expenditures.....................................   (239,623)     (115,217)        (667,869)
  Sale of subsidiary/investment in affiliated company......    175,000       150,508               --
  Other items, including net proceeds from UK leases.......    (19,485)      (12,086)           5,496
                                                             ---------     ---------      -----------
         Net cash used in investing activities.............   (314,274)     (241,336)      (1,001,091)
                                                             ---------     ---------      -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Net proceeds from issuance of long-term debt.............         --       223,845          195,712
  Net proceeds from issuance of guaranteed preferred
    beneficial interest in PGS junior subordinated debt
    securities (Note 11)...................................         --            --          138,914
  Net proceeds from issuance of subsidiary preferred stock
    (Note 11)..............................................    234,285            --               --
  Net proceeds from issuance of common stock, including
    stock option exercises.................................        816         7,425          220,024
  Repayment of long-term debt..............................    (11,414)      (15,447)         (29,924)
  Repayment of subsidiary preferred stock (Note 11)........    (77,280)           --               --
  Net increase (decrease) in revolving and short-term
    debt...................................................     (5,667)      (34,409)         283,334
  Principal payments under capital lease obligations.......     (7,806)       (7,775)         (13,437)
  Net payments under tax equalization swap contracts (Note
    17)....................................................    (64,575)       (8,068)              --
  Other....................................................         --            --           15,512
                                                             ---------     ---------      -----------
         Net cash provided by financing activities.........     68,359       165,571          810,135
                                                             ---------     ---------      -----------
  Effect of exchange rate changes in cash and cash
    equivalents............................................        (93)         (221)              49
  Net increase (decrease) in cash and cash equivalents.....    (34,306)       82,171            9,771
  Cash and cash equivalents at beginning of year...........    145,215        63,044           53,273
                                                             ---------     ---------      -----------
         Cash and cash equivalents at end of year..........  $ 110,909     $ 145,215      $    63,044
                                                             =========     =========      ===========
</Table>

  The accompanying notes are an integral part of these consolidated financial
                                  statements.
                                       F-5
<PAGE>

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

                                           COMMON STOCK         ADDITIONAL
                                      -----------------------    PAID-IN     RETAINED
                                        NUMBER      PAR VALUE    CAPITAL     EARNINGS
                                      -----------   ---------   ----------   ---------
                                      (IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
                                                   (AS RESTATED, NOTE 24)
<S>                                   <C>           <C>         <C>          <C>
Balance at December 31, 1998........   89,540,537    $62,312    $  996,499   $ 339,741
  Comprehensive loss:
    Net loss........................                                           (33,816)
    Other comprehensive loss........
  Issuance of common stock..........   11,159,500      7,232       205,674
  Exercise of stock options.........      909,550        582         6,700
                                      -----------    -------    ----------   ---------
Balance at December 31, 1999........  101,609,587     70,126     1,208,873     305,925
  Comprehensive loss:
    Net loss........................                                          (211,515)
    Other comprehensive loss........
  Exercise of stock options.........      738,400        416         7,011
                                      -----------    -------    ----------   ---------
Balance at December 31, 2000........  102,347,987     70,542     1,215,884      94,410
  Comprehensive income:
    Net income......................                                             4,453
    Other comprehensive loss........
  Issuance of common stock..........      900,000        493         8,558
  Exercise of stock options.........       98,000         54           673
                                      -----------    -------    ----------   ---------
Balance at December 31, 2001........  103,345,987    $71,089    $1,225,115   $  98,863
                                      ===========    =======    ==========   =========

<Caption>
                                                   ACCUMULATED OTHER
                                              COMPREHENSIVE INCOME (LOSS)
                                      -------------------------------------------
                                        FOREIGN       LONG-TERM
                                       CURRENCY     INTERCOMPANY     TOTAL OTHER
                                      TRANSLATION     CURRENCY      COMPREHENSIVE   SHAREHOLDERS'
                                      ADJUSTMENTS      LOSSES           LOSS           EQUITY
                                      -----------   -------------   -------------   -------------
                                         (IN THOUSANDS OF DOLLARS, EXCEPT FOR SHARE DATA)
                                                        (AS RESTATED, NOTE 24)
<S>                                   <C>           <C>             <C>             <C>
Balance at December 31, 1998........    $ 7,577       $(12,891)       $ (5,314)      $1,393,238
  Comprehensive loss:
    Net loss........................                                                    (33,816)
    Other comprehensive loss........     (5,387)        (5,806)        (11,193)         (11,193)
  Issuance of common stock..........                                                    212,906
  Exercise of stock options.........                                                      7,282
                                        -------       --------        --------       ----------
Balance at December 31, 1999........      2,190        (18,697)        (16,507)       1,568,417
  Comprehensive loss:
    Net loss........................                                                   (211,515)
    Other comprehensive loss........       (256)       (14,095)        (14,351)         (14,351)
  Exercise of stock options.........                                                      7,427
                                        -------       --------        --------       ----------
Balance at December 31, 2000........      1,934        (32,792)        (30,858)       1,349,978
  Comprehensive income:
    Net income......................                                                      4,453
    Other comprehensive loss........     (1,927)          (835)         (2,762)          (2,762)
  Issuance of common stock..........                                                      9,051
  Exercise of stock options.........                                                        727
                                        -------       --------        --------       ----------
Balance at December 31, 2001........    $     7       $(33,627)       $(33,620)      $1,361,447
                                        =======       ========        ========       ==========
</Table>

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

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- BASIS OF PRESENTATION, RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL
STATEMENTS AND LIQUIDITY

     Petroleum Geo-Services ASA (the "Company") provides geophysical services
and oil and gas production services. See further discussion of the Company's
services in Note 20.

     The Company is a Norwegian limited liability company and has prepared its
consolidated financial statements in accordance with accounting principles
generally accepted ("GAAP") in the United States of America ("US"). The
Company's consolidated financial statements include all accounts of Petroleum
Geo-Services ASA, its wholly owned subsidiaries and subsidiaries which it
controls. Investments in associated entities (companies and joint ventures) in
which the Company's ownership interests equal or exceed 20% and over which the
Company exercises significant, but not controlling, influence are accounted for
under the equity method. Other investments are accounted for at cost. All
significant intercompany accounts and transactions are eliminated in
consolidation. The Company did not have any significant transactions with
acquired companies in the periods prior to acquisition.

     As more fully described in Note 24, the accompanying financial statements
as of and for the years ended December 31, 2000 and 1999 have been restated (1)
to reflect fair value accounting for tax equalization swap contracts entered
into in 1998 and 1999 to hedge the Company's exposure to Norwegian taxes arising
out of the conversion, for Norwegian tax purposes, of the Company's US
dollar-denominated debt into Norwegian kroner (Note 17); (2) to reflect the
adoption of the US Securities and Exchange Commission's Staff Accounting
Bulletin ("SAB") No. 101, "Revenue Recognition in Financial Statements", which
became effective January 1, 2000, to our revenue recognition policy for some
types of volume seismic data licensing arrangements; (3) to adjust property and
equipment, multi-client library and depreciation and amortization to properly
reflect capitalized interest and depreciation and amortization amounts related
to two of the Company's seismic vessels and the upgrade of floating production,
storage and offloading ("FPSO") vessels; (4) to provide a valuation allowance
against certain deferred tax assets that properly reflects uncertainties about
the future utilization of these tax assets; (5) to amortize the multi-client
library in accordance with the Company's minimum amortization policy; and (6) to
properly amortize deferred assets over their useful lives and accrue defined
benefit pension obligations, commission/ royalty liabilities and lease
liabilities as incurred.

     In addition, certain reclassifications have been made to prior year amounts
to conform to the current year's presentation. In 2001, the Company reversed a
previously recorded $56.8 million contingent liability related to the Foinaven
field against goodwill recorded as part of the 1998 acquisition of the FPSO
operations of Awilco ASA.

     The accompanying financial statements have been prepared on the basis of
accounting principles that presume the realization of assets and the settlement
of liabilities in the ordinary course of business. Accordingly, the financial
statements do not purport to present the realizable values of all assets or the
settlement amounts of all liabilities.

     Because of the level of the Company's debt and other contractual cash
obligations, (1) a substantial portion of the Company's cash flow from
operations must be dedicated to debt service and payments of such obligations
and, to the extent so used, will not be available for operational purposes, (2)
the Company's ability to obtain additional financing in the future may be
limited, and (3) the Company's flexibility in reacting to changes in the
operating environment and economic conditions may be limited. If the Company
encounters difficulty in paying debt service or other obligations in the future,
it will be forced to take actions such as reducing or delaying capital
expenditures, reducing costs, selling assets, refinancing or restructuring its
debt or other obligations and seeking additional equity capital. The Company may
not be able to take any of these actions on satisfactory terms or at all.

                                       F-7
<PAGE>

     As of December 31, 2001, the Company had approximately $2.8 billion of
outstanding debt, lease and preferred securities obligations, with aggregate
contractual cash obligations summarized as follows (in millions):

<Table>
<Caption>
                                                           PAYMENTS DUE BY PERIOD
                                                   --------------------------------------
                                                                                2005 AND
CONTRACTUAL CASH OBLIGATIONS             TOTAL      2002       2003    2004    THEREAFTER
----------------------------            --------   ------     ------   -----   ----------
<S>                                     <C>        <C>        <C>      <C>     <C>
Debt obligations (Note 10)............  $2,161.3   $257.7(1)  $599.0   $10.2    $1,294.4
Capital lease obligations (Note
  12)(2)..............................      60.9     13.1       11.2     9.2        27.4
Operating lease obligations (Note
  12).................................     297.5    111.4       66.8    42.7        76.6
Guaranteed preferred beneficial
  interest in junior subordinated debt
  securities (Note 11)................     141.0       --         --      --       141.0
Mandatorily redeemable cumulative
  preferred securities (Note 11)(3)...     169.3     72.0       46.1    32.6        18.6
                                        --------   ------     ------   -----    --------
Total contractual cash obligations....  $2,830.0   $454.2     $723.1   $94.7    $1,558.0
                                        ========   ======     ======   =====    ========
</Table>

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

(1) Includes $225.0 million of floating rate notes that matured and were
    refinanced with a $250.0 million bank credit facility in March 2002. Such
    facility will mature in 2003.

(2) Reflects gross contractual commitments under capital leases.

(3) Assumes the Company's credit ratings remain at or above BB+ or Ba1 by
    Standard & Poor's Ratings Services ("Standard & Poor's"), a division of The
    McGraw-Hill Companies, Inc., or Moody's Investors Service, Inc. ("Moody's"),
    respectively.

     As of May 3, 2002, Moody's had rated the Company's senior unsecured debt at
Baa3, its lowest investment grade credit rating, and placed that credit rating
under review for possible downgrade. At that date, Standard & Poor's had rated
the Company's senior unsecured debt at BBB-, it lowest investment grade credit
rating, and had placed that credit rating on creditwatch with negative
implications, and Fitch IBCA, Duff & Phelps had rated our senior unsecured debt
at BBB-. In the event of a credit rating downgrade, the Company may have
difficulty obtaining financing and its cost of obtaining additional financing or
refinancing existing debt may be increased significantly. A credit rating
downgrade would cause the interest rate on the Company's $250.0 million
short-term bank facility (Note 10) to increase by up to 3.5% and would most
likely require the Company to seek refinancing alternatives for this facility
that would not otherwise be required. In the event that the Company's credit
ratings are downgraded to below BB+ or Ba1 by Standard & Poor's or Moody's,
respectively, the Company will be required to increase by 30% the quarterly
redemption of the mandatorily redeemable cumulative preferred securities of a
subsidiary which owns a portion of the multi-client library (Note 11). If those
credit ratings remain for a certain period of time, or deteriorate below BB- or
Ba3, respectively, the Company will be required to increase the quarterly
redemption of the preferred securities to an amount equal to 100% of the actual
revenue recognized from the licensing of the data held by that subsidiary. In
the event of a credit rating downgrade by both Standard & Poor's and Moody's,
the Company may be required to provide up to L35.7 million (approximately $52.0
million) in collateral or other credit support to one or more lessors or other
parties under UK leasing arrangements (Note 9), which could adversely impact
liquidity.

     The Company has entered into an agreement with Veritas DGC Inc.
("Veritas"), a geophysical services company, to combine the businesses of the
two companies (Note 3). The Company has also signed a definitive agreement to
sell its Atlantis subsidiary (Note 3). Both of these transactions include
conditions to closing that depend on the actions of third parties and are
therefore outside of the Company's control. If the Company fails to complete
either transaction, it could suffer adverse consequences including a downgrade
of its debt and trust preferred securities credit ratings by one or more rating
agencies, which would in turn cause the Company to incur increased interest
costs. In the event that the Atlantis sale is not completed, the Company will be
required to seek refinancing alternatives that

                                       F-8
<PAGE>

would not otherwise be required (Note 10). The Veritas transaction is itself
conditioned on closing the Atlantis sale.

NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  FOREIGN CURRENCY TRANSLATION.

     Although the Company's activities span the globe, its transactions are
primarily denominated in US dollars; therefore, the Company has adopted the US
dollar ("$") as its reporting currency. The Company uses the US dollar as the
functional currency for it and certain of its Norwegian subsidiaries.

     The financial statements of non-US subsidiaries using the US dollar as
their functional currency are translated as follows: non-monetary assets, share
par value and paid-in capital are translated at historical exchange rates;
revenue and expenses are translated at the average rates of exchange during the
period, except for depreciation and amortization, which are translated at
historical exchange rates; and all other financial statement accounts are
translated at the rate of exchange at period end. Remeasurement adjustments are
credited or charged directly to income, except for adjustments relating to
long-term intercompany borrowings, which are accumulated as a separate component
of shareholders' equity.

     The financial statements of non-US subsidiaries using their local currency
as their functional currency are translated using the current 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 are recorded as a
separate component of shareholders' equity.

     The Company's exchange rate between the Norwegian kroner and US dollar at
December 31, 2001 and 2000 was NOK 9.09 and NOK 8.84, respectively. The Company
recorded ($1.7) million, $2.9 million and $4.1 million in net foreign exchange
(losses) and gains, exclusive of the effects of the tax equalization swap
contracts (Note 17), for 2001, 2000 and 1999, respectively.

  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. As of
December 31, 2001 and 2000, $8.0 million and $4.0 million, respectively, in cash
balances related to payroll, taxes, insurance and our multi-client library
securitization (Note 11) were restricted.

  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, the Company sells the applicable assets to UK
financial institutions and leases the assets from the institutions under
long-term charters that give the Company the option to purchase the assets for a
de minimis amount at the end of the charter periods. Due to the nature of the
charters, the Company capitalizes the assets. The Company uses a substantial
portion of the proceeds from the arrangements to legally defease the present
value of the Company's future charter obligations for the assets. These UK
leases provide the financial institutions with the tax depreciation rights to
the assets and, therefore, the ability to utilize the related tax benefits.
Under its UK leases, the Company has indemnified the financial institutions
against certain future events that could reduce their expected after-tax returns
on the UK leases. These events include potential changes in UK tax laws and
interpretations, depreciation rates or interest rates. At the date that the
Company executes any UK lease, the Company treats the excess of the sales
proceeds received over the amount required to legally defease the charter
obligations as a deferred gain, due to the indemnification contingencies. The
deferred gain is recognizable as other income once the Company has determined
that the possibility of the indemnification contingencies occurring is remote.

                                       F-9
<PAGE>

  ACCOUNTING ESTIMATES.

     The preparation of financial statements in conformity with US GAAP requires
management to make various estimates, assumptions and judgments that affect the
reported amounts of assets and liabilities and the disclosure of contingent
assets and liabilities. In addition, such estimates, assumptions and judgments
can have a material effect on the amount of reported revenue and expenses during
a particular period. The Company reviews significant estimates, assumptions and
judgments no less frequently than annually. In many circumstances, the ultimate
outcomes 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, laws and regulations, changes in future operating plans and
the inherent imprecision associated with estimates.

  RECEIVABLES CREDIT RISK.

     The Company extends credit to various companies in the oil and gas industry
worldwide, which may be affected by changes in economic or other external
conditions. At December 31, 2001 and 2000, accounts receivable (both current and
long-term) were primarily from multinational integrated oil companies and
independent oil and 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 its customers and has provided for potential
credit losses through an allowance for doubtful accounts. Management does not
believe that the Company is exposed to concentrations of credit risk that are
likely to have a material adverse impact on the Company's financial position or
results of operations.

  MULTI-CLIENT LIBRARY.

     The multi-client library consists of seismic surveys that are to be
licensed to customers on a non-exclusive basis. All costs directly or indirectly
incurred in acquiring, processing and otherwise completing seismic surveys are
capitalized into the multi-client library, including the applicable portion of
the Company's interest costs. The multi-client library is stated at the lower of
survey costs less accumulated amortization or fair value.

     The Company records its investment in the multi-client library in a manner
consistent with its capital investment and operating decision analysis, which
generally results in each component of the multi-client library being recorded
and evaluated on a survey-by-survey basis, except for the multi-client library
in the Gulf of Mexico. Due to the density of the oil and gas prospectivity in
the Gulf of Mexico, the multi-client library is recorded and evaluated by
regions within the Gulf of Mexico and by year of completion.

     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, prospectivity, political risk, exploration
license periods and general economic conditions. 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.

     The Company's process for preparing expected revenue estimates begins with
local management input, but is reviewed and approved by the Company's senior
management. Beginning in 2002, changes to expected revenue estimates will
require approval from the Company's executive committee, with approved changes
effective in the following fiscal quarter. 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.

     The estimates of total expected revenue over the economic life of the
multi-client library are highly subjective, cover extended periods of time, and
are dependent on a number of factors outside the control of

                                       F-10
<PAGE>

the Company (including, among others, general economic conditions, prospectivity
within specific geographic regions and political and regulatory developments).
The Company's local sales and operating management estimate, at least annually,
the total expected revenue for each component of the multi-client library for
their respective region, as described above. On reorganizing its geophysical
operations in April 2001, the Company structured a sales team to focus on
developing volume sales arrangements covering the multi-client library on a
global basis. By the 2001 third quarter, the Company had a functional sales team
and business plan devoted to this new global sales strategy. In the 2001 fourth
quarter, the Company had sufficient evidence to make revenue estimates related
to this global sales strategy and, accordingly, included global volume sales
arrangement estimates in its total expected revenue estimates. Excluding the
effect of the revenue estimates for these global volume sales arrangements,
amortization of the multi-client library would have been approximately $3.0
million higher and an additional impairment of $1.3 million would have been
recorded for the year ended December 31, 2001.

     Although it is the Company's general policy to amortize the multi-client
library based on the proportion of the recognized revenue to the total expected
revenue, an integral element of the Company's amortization is the minimum
amortization policy. Under this policy, the Company requires that the book value
of each component of the multi-client library be reduced to a specified
percentage by year-end, based on the age of the component in relation to its
year of completion. This requirement is applied regardless of future-year
revenue estimates for the multi-client library component. The specified
percentage generates the maximum book value for each multi-client library
component as the product of the percentage multiplied by the original book value
of the multi-client library component. Any minimum amortization charges required
are then determined through a comparison of the remaining book value to the
maximum book value allowed for each component of the multi-client library.

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

<Table>
<Caption>
                                                   MAXIMUM BOOK VALUE FROM COMPLETION YEAR
                                                   ----------------------------------------
                                                     MARINE
                                                   COMPONENTS       MARINE
                                                   (EXCLUDING     COMPONENTS       LAND
YEAR FROM COMPLETION                                 BRAZIL)       (BRAZIL)     COMPONENTS
--------------------                               -----------    -----------   -----------
<S>                                                <C>            <C>           <C>
Year 1...........................................      100%           100%          100%
Year 2...........................................       70%            92%           60%
Year 3...........................................       55%            76%           40%
Year 4...........................................       40%            50%           20%
Year 5...........................................       30%            43%            0%
Year 6...........................................       20%            34%
Year 7...........................................       10%            20%
Year 8...........................................        0%             0%
</Table>

     The Company monitors its minimum amortization requirements on a quarterly
basis. During the second quarter of each year, the Company begins to record
minimum amortization charges, using revenue estimates for the remainder of the
current year to project the maximum book value of each multi-client library
component. However, the majority of the Company's minimum amortization charges
are recorded during the fourth quarter of each year due to the inherent
imprecision in estimating current year revenue. In the fourth quarters of 2001
and 2000, the Company recorded minimum amortization charges of $39.1 million and
$2.2 million, respectively. No minimum amortization charges were recorded for
the year ended December 31, 1999.

                                       F-11
<PAGE>

  PROPERTY AND EQUIPMENT.

     Property and equipment are stated at cost less accumulated depreciation.
Depreciation is calculated using a modified units-of-production method for
certain FPSO vessels and equipment and the straight-line method for all other
property and equipment, after allowing for residual values. The modified
units-of-production depreciation method used for certain of the Company's FPSO
vessels is based on an estimate of the total barrels of oil to be produced over
the useful life of the vessel. Because the actual number of barrels of oil
produced may ultimately differ from these estimates, it is possible that the
depreciation rates could deviate significantly over time. The estimated useful
lives for the Company's property and equipment are as follows:

<Table>
<Caption>
                                                               YEARS
                                                               -----
<S>                                                            <C>
Seismic vessels and FPSO vessels and equipment..............   20-30
Seismic and operations computer equipment...................    3-10
Leasehold improvements -- seismic vessels...................    1-30
Buildings and related leasehold improvements................    1-30
Fixtures, furniture and fittings............................     3-5
</Table>

     Expenditures for major property and equipment additions and improvements
are capitalized. The Company defers the non-capitalizable costs associated with
planned major maintenance activities and amortizes these costs over subsequent
periods, generally twelve to eighteen months. Expenditures for minor
replacement, maintenance and repair projects are charged to expense. The Company
capitalizes the applicable portion of its interest costs to major capital
projects that require a period of time to complete. 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 GAS PROPERTIES.

     The Company follows the full-cost method of accounting for oil and gas
properties, where all costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves are capitalized. Such
amounts include the cost of drilling and equipping productive wells, dry hole
costs, lease acquisition costs, interest capitalized on unevaluated leases and
other costs incidental to exploration and development activities. Overhead costs
capitalized include salary and benefits paid to employees directly engaged in
the acquisition, exploration and/or development of oil and gas properties as
well as other costs directly attributable to such activities. The Company
captures and accounts for such costs in separate cost centers on a
country-by-country basis.

     Capitalized costs are amortized using the unit-of-production method on a
country-by-country basis, using actual production quantities and estimates of
proved reserve quantities. Unevaluated properties are excluded from the
amortizable base. Costs associated with unevaluated properties are transferred
to evaluated property costs at such time as wells are completed, the properties
are sold, or management determines that the costs have been impaired. Future
development costs and dismantlement, restoration, and abandonment costs, net of
estimated salvage values, are added to the amortizable base.

     The Company limits, on a country-by-country basis, the costs of proved oil
and gas properties, net of accumulated depletion, depreciation and amortization
("DD&A"), to the estimated future net cash flows from proved oil and gas
reserves, generally using prices in effect at the end of the period held flat
for the life of production, discounted at 10%, net of related taxes. If the
capitalized cost of proved oil and gas properties exceeds this limit, the excess
is charged to expense in the period and reflected as additional DD&A.

     Proved oil and gas reserves are the estimated quantities of natural gas,
crude oil, condensate and natural gas liquids that geological and engineering
data demonstrate with reasonable certainty can be recovered in future years from
known reservoirs under existing economic and operating conditions.

                                       F-12
<PAGE>

Reserves are considered proved if they can be produced economically, as
demonstrated by either actual production or conclusive formation tests. The
Company emphasizes that the volumes of reserves are estimates which, by their
nature, are subject to revision. The estimates are made using all available
geological and reservoir data, as well as production performance data. These
estimates, made by the Company's engineers, are reviewed and revised, either
upward or downward, as warranted by additional data. Revisions are necessary due
to changes in assumptions based on, among other things, reservoir performance,
prices, economic conditions and governmental restrictions. Decreases in prices,
for example, may cause a reduction in some proved reserves due to uneconomic
conditions.

     The Company's oil and gas assets at December 31, 2001 are owned by its
Atlantis subsidiary. On January 22, 2002, the Company entered into definitive
agreement with China National Chemicals Import and Export Corporation
("Sinochem") for the sale of its Atlantis subsidiary (Note 3).

  GOODWILL AND OTHER LONG-TERM ASSETS.

     Goodwill is stated at cost less accumulated amortization. Goodwill
amortization is calculated on a straight-line basis over the estimated life,
with a maximum life of 40 years.

     Other long-term assets consist of investments in associated entities,
long-term receivables, deferred tax assets, direct costs of software product
development, patents, royalties and licenses. Other long-term assets which are
amortizable are stated at cost less accumulated amortization. Amortization is
calculated on a straight-line basis over the estimated useful lives of the
related assets, with a maximum life of 10 years.

     Amortization of goodwill and other long-term assets was $15.4 million,
$15.2 million and $14.3 million for the years ended December 31, 2001, 2000 and
1999, respectively.

  ASSET RECOVERABILITY.

     The Company's management evaluates the recorded balances of its property
and equipment, goodwill and other long-term assets for impairment whenever
events or changes in circumstances indicate that the carrying amounts may not be
appropriate. This evaluation is based on a comparison of the assets' fair
values, which are generally based on forecasts of cash flows associated with the
assets, to the assets' carrying amounts. Any impairment loss is recorded as the
difference between the assets' carrying amounts and fair values. As discussed in
Note 23, during the three-year period ended December 31, 2001 certain events and
circumstances warranted revision to the remaining useful lives and affected the
recoverability of the Company's assets.

  LOSS CONTRACTS.

     The Company reviews its revenue-producing contracts in the ordinary course
of business to determine if estimated costs to service the contract exceed the
estimated contract revenue. Any resulting net loss indicated for the contract is
expensed at the time the loss is determined. If the Company estimates
intermittent periods of profitability over the life of a loss contract, this
profitability is deferred against the future loss.

  DERIVATIVE FINANCIAL INSTRUMENTS.

     Derivative financial instruments are used periodically by the Company in
the management of its foreign currency exchange rate exposure. The Company does
not engage in derivative financial instrument transactions for speculative
purposes. The derivative contracts are entered into with major international
financial institutions. The likelihood of non-performance by the Company's
counterparties under these contracts is considered to be remote.

     Gains and losses attributable to forward foreign exchange contracts and
option contracts that do not qualify for hedge accounting, including tax
equalization swap contracts (Note 17), are recognized in income as they arise.
As of December 31, 2001 and 2000, the Company did not have outstanding any
derivative financial instruments which qualified for hedge accounting.
                                       F-13
<PAGE>

  REVENUE RECOGNITION.

     Beginning January 1, 2000, the Company recognizes revenue in accordance
with SAB No. 101. The Company's specific revenue recognition policies are as
follows:

     GEOPHYSICAL SERVICES

     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 Company's
multi-client data library. In each case, the portion of the multi-client library
for which an access license is being granted is complete and ready for use. 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 at the point that the customer has executed a valid license agreement, the
customer has been granted access to the licensed portion of the multi-client
library and collection is reasonably assured.

     Volume sales agreements -- The Company enters into a customer arrangement
in which the Company agrees to grant licenses to the customer for access to a
specified number of blocks of the multi-client library within a defined
geographical area. These arrangements 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.

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

     Pre-funding arrangements -- The Company obtains funding from a limited
number of customers before a seismic project commences from time to time. In
return for the prefunding, the customer typically gains the ability to
direct/influence the project specifications, advance access to data as it is
being acquired and discounted pricing.

     The Company recognizes prefunding revenue as the services are performed on
a percentage-of-completion basis. The Company evaluates the progress to date, in
a manner generally consistent with the physical progress off the project, and
recognizes revenue based on the ratio of the project's progress to date to the
total project.

     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 scope and
terms of these proprietary sales vary substantially. The Company recognizes
proprietary/contract revenue as the services are performed and become chargeable
to the customer.

     OTHER GEOPHYSICAL SERVICES

     Revenue from the Company's other geophysical services is recognized as the
services are performed.

     PRODUCTION SERVICES

     Tariff-based revenue from the Company's floating production services is
recognized as production occurs, while day-rate revenue is recognized over the
passage of time. Production management services revenue is recognized as the
services are performed. Performance-based incentive fees are accrued when there
is objective evidence that the performance criteria have been met.

                                       F-14
<PAGE>

  INCOME TAXES.

     The Company provides for all current taxes payable and for deferred taxes
arising from temporary differences between the tax bases of assets and
liabilities and their reported amounts in the financial statements, based on
enacted tax rates and laws in effect for the years in which differences are
expected to reverse. Income tax benefits and liabilities arising from
tax-deductible share issue costs are recorded directly to shareholders' equity.
Except where required by law, Norwegian income taxes are not accrued for
unremitted earnings of international operations that have been, or are intended
to be, reinvested indefinitely. Valuation allowances are provided against
deferred tax assets when management determines that it is more likely than not
that a future tax benefit will not be realized.

  NEW ACCOUNTING STANDARDS.

     During 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS
No. 141 requires that the purchase method of accounting be used for all business
combinations initiated after June 30, 2001. Effective January 1, 2002, SFAS No.
142 suspends amortization of goodwill and intangible assets with indefinite
lives and, instead, requires an annual impairment review based on a comparison
of fair value to carrying value. SFAS No. 142 requires that the fair value
determination be completed by June 30, 2002, with any resulting transitional
impairment to be recorded by December 31, 2002 and reflected retroactively as of
January 1, 2002 as the cumulative effect of an accounting change. Any
impairments other than transitional impairment will be recognized in continuing
operations. The Company is developing its fair value calculations and has not
yet determined the impact of adopting SFAS No. 142.

     During 2001, the FASB also issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 establishes accounting and reporting
standards for the retirement of long-lived assets requiring the fair value of an
asset retirement obligation to be recognized as a liability in the period in
which it is incurred, with the associated costs capitalized as part of the
carrying amount of the long-lived asset. SFAS No. 143 is effective for the
Company beginning January 1, 2003, and any effects on adoption will be reflected
as a cumulative effect of an accounting change. The Company has not yet
determined the impact of SFAS No. 143.

     Also during 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses, in part,
issues related to implementation of SFAS No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 144
is effective for the Company as of January 1, 2002. The Company does not expect
to recognize any material effects on the prospective implementation of SFAS No.
144.

     Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities." SFAS No. 133 establishes
accounting and reporting standards requiring that every derivative financial
instrument be recorded in the balance sheet as either an asset or a liability
measured at its fair value, with certain changes in fair value recognized
currently in earnings. Under SFAS No. 133, the Company's derivative financial
instruments are recognized at fair value (including any interim settlement value
determined by the counterparty) in each reporting period, with any periodic
adjustments to fair value recognized in the results of operations. The Company
did not recognize any material effects on adoption of SFAS No. 133. However, see
Notes 17 and 24 for further discussion of the Company's derivative financial
instruments and the restatement related to these instruments.

     The Company's financial statements and related disclosures reflect the
January 1, 2000 adoption of SAB No. 101, "Revenue Recognition in Financial
Statements." Application of this SAB required the deferral of revenue
recognition on certain types of volume seismic data licensing arrangements until
the time that customer enters into a license agreement for specific data.
Accordingly, the Company adjusted revenue ($22.8 million), amortization ($11.4
million) and commission expense ($2.3 million) and recognized an aggregate
charge to income of $6.6 million, net of tax benefits of $2.5 million, as of
                                       F-15
<PAGE>

January 1, 2000 as the cumulative effect of the change in accounting principle.
See Note 23 for further discussion of these adjustments. As a result of the
application of SAB No. 101, the Company has deferred $26.0 million and $15.6
million of revenue relating to certain volume sales agreements in effect as of
December 31, 2001 and 2000, respectively.

     Effective January 1, 1999, the Company adopted Statement of Position
("SOP") 98-5, "Reporting on the Costs of Start-up Activities." Accordingly, the
Company expensed as a cumulative effect of an accounting change all previously
capitalized start-up costs. The $20.0 million in expensed costs, net of income
tax benefits of $8.1 million, included costs related to the start-up of the
Company's floating production business, the reservoir monitoring business and
the multi-component, vertical cable and land seismic businesses, as well as
costs related to the opening of various worldwide offices. Subsequent to
adoption, all start-up costs are expensed as incurred.

NOTE 3 -- ACQUISITIONS AND DISPOSITIONS

     On November 26, 2001, the Company entered into a definitive agreement with
Veritas to combine the businesses of the two companies under a new Cayman
Islands holding company, referred to as "Caymanco." Under the agreement,
Caymanco will make an exchange offer to issue its ordinary shares in exchange
for the Company's outstanding shares and American Depositary Shares ("ADSs").
Following the closing of the exchange offer, Veritas will merge with a wholly
owned subsidiary of Caymanco. Upon closing of the exchange offer and the merger,
the Company and Veritas will become subsidiaries of Caymanco. The closing of the
transaction is subject to a number of conditions, including: (1) the tender in
the exchange offer of Company shares and ADSs representing more than 90% of the
shares outstanding as of the expiration of the exchange offer, which percentage
may be reduced in limited circumstances described in the agreement; (2) the
approval of the merger by the stockholders of Veritas; (3) the receipt of
applicable regulatory clearances; (4) the Company having in effect definitive
credit agreements or binding commitments providing for credit capacity of $430
million; (5) Veritas' having in effect definitive credit agreements or binding
commitments providing for credit capacity of $235 million; (6) the authorization
of the ordinary shares of Caymanco for listing on the New York Stock Exchange;
(7) the Company having completed the sale of its Atlantis subsidiary (discussed
further below); (8) the Company having entered into replacement employment
agreements with some of its active employees; and (9) other customary
conditions, including the absence of any events or series of events that has had
or would have a material adverse effect on Veritas or the Company.

     Under the agreement, a material adverse effect will be deemed to have
occurred and either party may terminate the agreement if, among other things:
(1) the settlement price for the NYMEX natural gas futures contract for delivery
12 months following the month in which the relevant date of determination occurs
falls below $2.25 per MMBtu for 20 consecutive trading days; or (2) the
settlement price for the NYMEX light sweet crude oil futures contract for
delivery 12 months following the month in which the relevant date of
determination occurs falls below $12.50 per barrel for 20 consecutive trading
days.

     During 2002, the Company has had discussions with Veritas about amending
the terms of the agreement in various respects. Although no definitive amendment
has been reached, the Company expects any such amendment to include the
following key terms: (1) Company shareholders would receive 0.40 shares
(previously 0.47 shares) of Caymanco for each Company share and ADS, and Veritas
shareholders would receive one share of Caymanco for each Veritas share,
resulting in Veritas shareholders owning approximately 44% of the Caymanco
shares and Company shareholders owning approximately 56% of the Caymanco shares
upon completion of the transaction (assuming all Company shares and ADSs are
tendered and accepted in the exchange offer); (2) Veritas would be entitled to
nominate six of the proposed ten directors of Caymanco while the Company would
be entitled to nominate four directors; (3) David B. Robson, the Chief Executive
Officer of Veritas, would be the Chief Executive Officer of Caymanco and Reidar
Michaelsen, the Company's Chairman and Chief Executive Officer, would be the
Chairman of the Board; (4) Matthew D. Fitzgerald, the Chief Financial Officer of
Veritas, would be the Chief Financial Officer of Caymanco; and (5) the
transaction would be conditioned upon Veritas being treated as the acquiring
company for accounting purposes.
                                       F-16
<PAGE>

     In April 2002, Veritas reported that the staff of the US Securities and
Exchange Commission would not object to Veritas being treated as the accounting
acquiror. Any amendment to the agreement with Veritas would be subject to final
approval of the boards of directors of each company.

     If the Company and Veritas amend the original agreement along the lines
described above and assuming all conditions precedent were satisfied or waived,
the transaction is expected to close during the third quarter of 2002. However,
the Company or Veritas may not be able to satisfy all the conditions to closing,
including the sale of Atlantis, and there is no assurance that any conditions
that are not satisfied will be waived. In addition, the original agreement,
which is still in effect, provides that either party may terminate the agreement
if the transaction has not been effected by June 30, 2002. The transaction is
expected to be a taxable transaction to the Company's Norwegian shareholders
unless a specific exemption is granted by the Norwegian ministry of finance and
a taxable transaction to the Company's US shareholders.

     The transaction will be accounted for using the purchase method of
accounting. The Company and Veritas have not had any significant intercompany
transactions. On completion of the transaction, certain members of the Company's
management could be entitled to receive compensation of up to $22.1 million due
to the change in control of the Company. Such compensation amounts are not
accruable until the transaction is consummated, and are therefore not reflected
in the Company's statement of operations or financial position.

     In July 2001, the Company consummated the acquisition of Diamond
Geophysical Services Corporation ("Diamond"), a company specializing in the
design and marketing of 3D multi-client seismic surveys. Consideration paid for
the net assets acquired consisted of $1.0 million in cash paid and approximately
$9.1 million in equity issued (in the form of 900,000 shares) to the former
owners, as well as the assumption by the Company of approximately $1.4 million
in assets and $1.0 million in liabilities. The transaction was treated as a
purchase for accounting purposes, with the assets acquired and the liabilities
assumed recorded at their fair values, including $9.7 million in goodwill. Prior
to the acquisition (beginning in 1994), Diamond was the exclusive broker of a
significant portion of the Company's Gulf of Mexico multi-client library, and
received sales commissions and a monthly retainer for services from the Company.

     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 ($175.0 in gross
sale proceeds less $9.3 million in working capital adjustments). The Company
recognized a $138.5 million gain on the sale, excluding taxes of $40.4 million,
which was classified as an unusual item in the Company's results of operations.
The Company's results of operations for the 2001 period (prior to consummation
of the sale), 2000 and 1999 included pretax (loss)/income of ($3.7) million,
$0.9 million and $0.6 million, respectively, related to the data management
business. The financial position of the data management business was not
material to the Company's consolidated financial position for any year
presented.

     In December 2000, the Company sold all of its holdings (5.4 million shares)
in Spinnaker Exploration Company for net proceeds of $150.5 million. At December
31, 2000, $70.0 million of the proceeds had been used to repay indebtedness
outstanding under the Company's revolving bank credit facility. A $54.7 million
pretax gain on this transactions was recognized as income from equity
investments.

  SUBSEQUENT EVENTS.

     On January 22, 2002, the Company entered into a definitive agreement with
Sinochem for the sale of the Company's Atlantis subsidiary, which is a part of
the Company's production operations segment. Under the terms of the definitive
agreement, total proceeds from the sale of Atlantis are expected to approximate
$200 million in cash, plus certain qualifying capital expenditures incurred
during 2002. Sinochem also has agreed to assume $20.5 million of Atlantis'
short-term debt. The Company is required

                                       F-17
<PAGE>

to use $175.0 of the net proceeds received from the Atlantis sale to repay a
portion of the Company's $250.0 million short-term bank facility (Note 10).

     As of December 31, 2001, Atlantis' assets and liabilities to be sold
included the following: $3.6 million in cash, $0.5 million in other current
assets, $0.2 million in property and equipment, $171.1 million in oil and gas
assets, $4.0 million in net deferred tax assets, $20.5 million in short-term
debt and $9.2 million in current liabilities. The Company did not record any
impairment charges related to the Atlantis net assets since the carrying value
did not exceed the fair value (less estimated costs to sell). Atlantis' pretax
(loss) of ($4.0) million, ($2.3) million and $(11.4) million for the years ended
December 31, 2001, 2000 and 1999, respectively, are included in the Company's
results of operations for those periods. Interest capitalized into oil and gas
assets was $6.7 million, $7.9 million and $4.2 million for the years ended
December 31, 2001, 2000 and 1999, respectively.

     Consummation of the sale is subject to certain conditions, including the
receipt of certain consents and waivers from governmental authorities and
partners. On April 22, 2002, the Company agreed with Sinochem to extend the
period to close the sale through June 28, 2002, although Sinochem has the right
under the extension to terminate the agreement after May 27, 2002. Under the
extension agreement, if the required closing conditions are satisfied or are
waived by Sinochem after May 20, 2002, then the sale proceeds will be reduced by
$100,000 per day from the period May 13, 2002 through the date that the closing
conditions are so satisfied or waived. In the event that the Company terminates
the definitive agreement after June 28, 2002, the Company may be required to pay
a $1.4 million termination fee to Sinochem.

     During the 2002 first quarter, the Company entered into purchase
commitments for an aggregate 70% interest in Production License (PL) 038 on the
Norwegian Continental Shelf of the North Sea. The interests are to be purchased
from Statoil (which holds a 28% interest in PL 038) and Norsk Hydro (which holds
a 42% interest in PL 038). As consideration for its 70% interest, the Company
will assume a portion of the abandonment liabilities associated with the fields
on the license as well as any future environmental liabilities that may be
generated by production on the fields. The estimates for these liabilities range
up to $32.0 million in gross costs, or $12.0 million in after-tax costs. The
license purchases are contingent on the approval of Norwegian authorities and
expected to close during the 2002 third quarter. Upon completion of the
purchases, the Company's 30% partner will be the Norwegian government's State
Direct Financial Interest.

NOTE 4 -- ACCOUNTS RECEIVABLE

     The Company has recorded allowances for doubtful accounts of $3.6 million
and $4.2 million at December 31, 2001 and 2000, respectively. The Company has
recorded $83.7 million and $117.2 million of unbilled receivables at December
31, 2001 and 2000, respectively; these receivables relate to revenue that has
been recognized but is not yet billable under the specific broker or customer
agreements. Of these unbilled receivables, $11.1 million and $23.3 million were
net long-term receivables at December 31, 2001 and 2000, respectively.

NOTE 5 -- MULTI-CLIENT LIBRARY

     The components of the multi-client library, net of accumulated
amortization, are summarized as follows:

<Table>
<Caption>
                                                                     DECEMBER 31,
                                                              --------------------------
                                                                 2001           2000
                                                              -----------    -----------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>            <C>
Multi-client seismic surveys, completed.....................   $841,108       $628,909
Multi-client seismic surveys, work in progress..............     76,964        219,811
                                                               --------       --------
          Total.............................................   $918,072       $848,720
                                                               ========       ========
</Table>

                                       F-18
<PAGE>

     The multi-client library as of December 31, 2001 allocated by the year in
which the components were completed are summarized as follows:

<Table>
<Caption>
                                                                NET BOOK
                                                                  VALUE
                                                              -------------
                                                              (IN THOUSANDS
                                                               OF DOLLARS)
<S>                                                           <C>
COMPLETED SURVEYS:
Completed before 1996.......................................    $  4,297
Completed during 1996.......................................      20,954
Completed during 1997.......................................      22,835
Completed during 1998.......................................      69,730
Completed during 1999.......................................     188,373
Completed during 2000.......................................     234,824
Completed during 2001.......................................     300,095
                                                                --------
  Completed surveys.........................................     841,108
Surveys in progress.........................................      76,964
                                                                --------
Multi-client library........................................    $918,072
                                                                ========
</Table>

     Amortization expense was $195.4 million, $142.6 million and $137.5 million
for the years ended December 31, 2001, 2000 and 1999, respectively. Amortization
expense for the years ended December 31, 2001 and 2000 included $39.1 million
and $2.2 million, respectively in charges required under the Company's minimum
amortization policy for the multi-client library (Note 1).

     The application of the Company's minimum amortization requirements to the
components of the multi-client library as of December 31, 2001 are summarized as
follows:

<Table>
<Caption>
                                                                 MINIMUM
                                                                  FUTURE
                                                               AMORTIZATION
                                                              --------------
                                                              (IN THOUSANDS
                                                               OF DOLLARS)
<S>                                                           <C>
During 2002.................................................     $100,234
During 2003.................................................      171,092
During 2004.................................................      187,120
During 2005.................................................      145,589
During 2006.................................................      130,335
During 2007.................................................       98,516
During 2008.................................................       73,898
During 2009.................................................       11,288
                                                                 --------
Future amortization.........................................     $918,072
                                                                 ========
</Table>

     These minimum amortization requirements are calculated as if there will be
no future sales of these components. The Company believes that the likelihood of
recognizing these precise 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 apply to the multi-client
library on a component basis rather than in the aggregate, the Company may incur
minimum amortization charges in a year even if the aggregate amount of ordinary
amortization charges recognized exceeds the aggregate minimum amortization
charges.

     Interest capitalized into the multi-client library was $15.9 million, $21.7
million and $26.6 million for the years ended December 31, 2001, 2000 and 1999,
respectively.

                                       F-19
<PAGE>

NOTE 6 -- OTHER CURRENT ASSETS, NET AND ACCRUED EXPENSES

     Other current assets, net at December 31, 2001 include $28.0 million in
prepaid operating expenses; other current assets, net at December 31, 2000
include $27.9 million in prepaid operating expenses. Accrued expenses at
December 31, 2001 include a $44.6 million liability related to the fair value of
tax equalization swap contracts (Note 17) and $29.4 million in customer advances
and deferred revenue. Accrued expenses at December 31, 2000 include a $91.2
million liability related to the fair value of tax equalization swap contracts
(Note 17), $27.7 million in customer advances and deferred revenue, $21.2
million in accrued interest, $63.3 million in accrued loss contracts (customer
contracts and vessel contracts), $22.1 million in accrued upgrade costs related
to the Petrojarl I and Ramform Banff and $23.2 million in accrued vessel
operating costs.

NOTE 7 -- PROPERTY AND EQUIPMENT

     The components of property and equipment are summarized as follows:

<Table>
<Caption>
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2001          2000
                                                              -----------   -----------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>           <C>
FPSO vessels and equipment..................................  $1,818,609    $1,698,522
Seismic vessels, including leasehold improvements...........     486,105       493,263
Seismic and operations computer equipment...................     537,742       483,340
Buildings, including leasehold improvements, and other......      20,507        22,450
Fixtures, furniture and fittings............................      56,800        67,983
                                                              ----------    ----------
                                                               2,919,763     2,765,558
Accumulated depreciation....................................    (637,522)     (513,615)
                                                              ----------    ----------
          Total.............................................  $2,282,241    $2,251,943
                                                              ==========    ==========
</Table>

     The gross cost of property and equipment includes $68.1 million and $54.9
million (primarily seismic and computer equipment) relating to capital leases
(Note 12) as of December 31, 2001 and 2000, respectively, and reflected $30.2
million and $44.6 million of depreciation capitalized into the multi-client
library for the years then ended, respectively. Accumulated depreciation of
property and equipment includes $24.2 million and $36.2 million relating to
capital leases as of December 31, 2001 and 2000, respectively. Net depreciation
expense was $123.7 million, $105.8 million and $86.8 million for the years ended
December 31, 2001, 2000 and 1999, respectively. Interest capitalized into
property and equipment was $3.9 million, $5.4 million and $9.3 million for the
years ended December 31, 2001, 2000 and 1999, respectively. Property and
equipment balances at December 31, 2000 reflect the significant impairment
charges and restructuring activities undertaken by the Company in 2000 (Note
23).

     The property and equipment balances related to FPSO vessels and equipment
included significant capital additions recorded as part of FPSO upgrade projects
completed during 2001 on Ramform Banff, Petrojarl Foinaven and Petrojarl I. On
completion of the Petrojarl I FPSO upgrade during the 2001 third quarter, the
Company extended the remaining useful life of the FPSO system from 17 years to
27 years. As a result of this change in estimate, future annual depreciation for
the Petrojarl I FPSO system will be reduced by approximately $5.0 million.

NOTE 8 -- LOSS CONTRACTS

     The Company had $8.2 million in accrued losses related to the Ramform
Banff's Banff field contract as of December 31, 2001. The Company and its
customer under the contract are evaluating alternatives to the current field
production scenario, and the Company is unable to reasonably estimate whether
and at what level contract losses will be incurred in the future. The Company
will re-evaluate the need for loss contract accruals for Ramform Banff in future
periods, and may be required to accrue additional loss contract accruals.
Additionally, the Company has invested $64.6 million in subsea equipment on the
Banff

                                       F-20
<PAGE>

field as of December 31, 2001; in the event that the Ramform Banff exits the
Banff field prior to the contract expiration date (one alternative currently
being evaluated), the Company may be required to impair the value of this
equipment.

NOTE 9 -- UK LEASES

     The Company has periodically executed UK leases relating to certain seismic
and FPSO vessels and/or equipment. Under the leases, the Company sells the
applicable assets to UK financial institutions and leases the assets from the
institutions under long-term charters that give the Company the option to
purchase the assets for a de minimis amount at the end of the charter periods.
Due to the nature of the charters, the Company capitalizes the assets. The
Company uses a substantial portion of the proceeds from the arrangements to
legally defease the present value of the Company's future charter obligations
for the assets.

     The Company had $1.4 billion and $1.5 billion in property and equipment
under UK leases at December 31, 2001 and 2000, respectively. In the event of a
downgrade of the Company's credit rating to below BBB- and Baa3 by Standard &
Poor's and Moody's, respectively, the Company may be required to provide up to
L35.7 million (approximately $52.0 million) in collateral or credit support to
one or more lessors or other parties under outstanding UK leases.

     As of the date of the Awilco acquisition (Note 3), Awilco had $51.0 million
in indemnification contingencies recorded for a UK lease on the Petrojarl
Foinaven, $25.0 million of which was reversed against goodwill in the year of
acquisition. During the year ended December 31, 2000, the Company removed the
remaining indemnification contingencies and, as a result, recognized the
remaining $26.0 million deferred UK lease gain in income.

     During 1999, the Company recognized $19.1 million in UK lease gains on
delivery of two seismic vessels.

NOTE 10 -- DEBT

  LONG-TERM DEBT, EXCLUDING REVOLVING BANK CREDIT FACILITIES.

     Long-term debt, excluding revolving bank credit facilities, consists of the
following:

<Table>
<Caption>
                                           YEAR-END                       YEAR-END
                                           WEIGHTED                       WEIGHTED
                                            AVERAGE      DECEMBER 31,      AVERAGE      DECEMBER 31,
                                         INTEREST RATE       2001       INTEREST RATE       2000
                                         -------------   ------------   -------------   ------------
                                                          (IN THOUSANDS OF DOLLARS)
<S>                                      <C>             <C>            <C>             <C>
Bank loans/public notes:
  Secured..............................       8.3%        $  119,884         8.3%        $  130,965
  Unsecured............................       6.7%         1,680,088         7.2%         1,679,360
Other loans:
  Secured..............................       7.5%                97         7.5%               186
  Unsecured............................      13.0%               726          --                 --
                                             -----        ----------                     ----------
                                                           1,800,795                      1,810,511
Current portion........................                     (237,224)                       (11,090)
                                                          ----------                     ----------
          Long-term portion                               $1,563,571                     $1,799,421
                                                          ==========                     ==========
</Table>

     In March 2000, the Company issued $225.0 million of senior unsecured notes.
The notes carried a floating interest rate equal to 0.65% over three-month
LIBOR, subject to quarterly adjustment, with interest payable quarterly. The
notes matured in March 2002. See "-- Subsequent Event" below. The net proceeds
from this issuance were primarily used to repay indebtedness outstanding under
the Company's revolving bank credit facility.

                                       F-21
<PAGE>

     In July 1999, the Company entered into a $350.0 million unsecured bridge
facility in order to finance the acquisition of the Petrojarl Varg FPSO. The
Company then issued $200.0 million of senior unsecured notes for net proceeds of
$195.7 million. The net proceeds on these notes, together with the net proceeds
from the Company's ADS/share offering (Note 15), were used to repay a $350.0
million bank bridge loan facility as well as indebtedness outstanding under the
Company's revolving bank credit facility. The notes carry an interest rate of
8.2%, with interest payable semi-annually, and mature in July 2029. These notes
can be redeemed at the Company's option, in whole or in part, at any time,
subject to an early redemption premium.

     In November 1998, the Company issued $250.0 million of senior unsecured
notes. The notes carry an interest rate of 6.3%, with interest payable
semi-annually, and mature in November 2003. These notes can be redeemed at the
Company's option, in whole or in part, at any time, subject to an early
redemption premium. The net proceeds from this issuance were used to repay
indebtedness outstanding under the Company's revolving bank credit facilities.
In April 1998, the Company issued $450.0 million and $200.0 million of senior
unsecured notes. The notes carry interest rates of 7.1% and 6.6%, respectively,
with interest payable semi-annually, and mature in March 2028 and March 2008,
respectively. These notes can be redeemed at the Company's option, in whole or
in part, at any time, subject to an early redemption premium. The net proceeds
from this issuance were primarily used to repay indebtedness and certain other
obligations that were assumed in the Awilco acquisition as well as indebtedness
outstanding under the Company's revolving bank credit facilities.

     In April 1997, the Company purchased all of the capital stock of a company
that indirectly owns the Ramform Explorer and the Ramform Challenger seismic
vessels. This company has outstanding mortgage notes, in an original principal
amount of $165.7 million, secured by the Ramform Explorer and the Ramform
Challenger. The notes carry an interest rate of 8.3%, with interest payable
semi-annually, and mature in June 2011. The notes are subject to mandatory
redemption through semi-annual sinking fund payments through June 2011. The
notes can be redeemed at the holder's option on any sinking fund payment date on
or after June 2006, in whole but not in part, subject to an early redemption
premium. In March 1997, the Company issued $360.0 million of senior unsecured
notes. The notes carry an interest rate of 7.5%, with interest payable
semi-annually, and mature in March 2007. These notes can be redeemed at the
Company's option, in whole or in part, at any time, subject to an early
redemption premium. The net proceeds from this issuance were used, in part, to
redeem $125.0 million of senior notes which were scheduled to begin amortizing
in 2001.

  REVOLVING BANK CREDIT FACILITIES.

     In September 1998, the Company entered into an unsecured five-year $430.0
million revolving bank credit facility. The facility matures in 2003 and bears
interest at LIBOR, plus a margin of either 0.35% or 0.40% depending on the
Company's level of indebtedness, and carries quarterly commitment fees on any
unused portion of the facility of 0.18%. The facility is subject to a material
adverse change clause regarding the Company's financial condition and to other
conditions to borrowing that are customary for such types of facilities.

     During the year ended December 31, 2001, the Company borrowed an aggregate
of $180.0 million under the $430.0 million revolving bank credit facility, with
a weighted average interest rate of 3.1%. The average and maximum borrowings
outstanding were $260.8 million and $360.0 million, respectively, and the
weighted average interest rate was 2.7% on outstanding balances at December 31,
2001. At December 31, 2001, the Company had $90.0 million available for
borrowing under this facility. During the year ended December 31, 2000, the
Company borrowed an aggregate of $240.0 million under the revolving facility,
with a weighted average interest rate of 7.0%. The average and maximum
borrowings outstanding for the year ended December 31, 2000 were $328.3 million
and $430.0 million, respectively. At December 31, 2000, the Company had $70.0
million available for borrowing under this facility, with the outstanding
balance of $360.0 million carrying a weighted average interest rate of 7.1%.

                                       F-22
<PAGE>

  SHORT-TERM DEBT.

     During December 2000, the Company entered into a $75.0 million unsecured
credit facility with a syndicate of banks. The facility was drawn to $30.0
million, with $27.5 million in average outstanding borrowings, and repaid in
full by December 31, 2001. The facility bore interest at LIBOR, plus a margin
that escalated from 0.4% to 0.6%; the average interest rate for the year was
4.5%. The facility matured in December 2001 and was fully repaid by this date.
At December 31, 2000, there was no indebtedness outstanding under this credit
facility.

     Additionally during December 2000, the Company entered into a $21.0 million
unsecured bank credit facility. The facility bears interest at a LIBOR-based
rate plus a margin which can range from 0.63% to 1.4%; the interest rate
averaged 4.4% during 2001 and was 2.8% at December 31, 2001 (7.2% for 2000).
This facility is payable in installments through 2003, with the payment
installments tied to future production from certain oil and gas assets. At
December 31, 2001 and 2000, respectively, $20.5 million and $3.3 million was
outstanding under this credit facility. This debt will be assumed by Sinochem in
the sale of Atlantis (Note 3).

     The Company also draws short-term debt with various international banks
based on working capital requirements. Short-term debt (excluding the Atlantis
facility) was $3.0 million at December 31, 2000. There was no such short-term
debt at December 31, 2001. Average and maximum short-term debt balances for the
year ended December 31, 2001 were $19.2 million and $40.0 million, respectively,
and for 2000 were $18.3 million and $46.8 million, respectively. The associated
weighted average interest rate for the year ended December 31, 2001 was 4.4%.
The associated weighted average interest rates as of and for the year ended
December 31, 2000 were 8.3% and 7.1%, respectively.

  MATURITIES.

     Aggregate maturities of the Company's debt, as of December 31, 2001 are as
follows:

<Table>
<Caption>
                      DECEMBER 31,                        (IN THOUSANDS OF DOLLARS)
                      ------------                        -------------------------
<S>                                                       <C>
2002....................................................         $  257,724
2003....................................................            598,958
2004....................................................             10,200
2005....................................................             10,990
2006....................................................             11,920
Thereafter..............................................          1,271,503
                                                                 ----------
          Total.........................................         $2,161,295
                                                                 ==========
</Table>

  COVENANTS.

     In addition to customary representations and warranties, certain of the
Company's debt agreements and UK lease agreements (Note 9) include covenants
relating to the maintenance of minimum net worth levels, interest coverage
ratios and debt leverage ratios. Additionally, certain covenants restrict
certain types of indebtedness, such as subsidiary indebtedness, liens on assets,
cash dividends and sale/leaseback transactions. The Company was in compliance
with all such covenants at December 31, 2001.

  PLEDGED ASSETS.

     Seismic vessels and related equipment carrying a book value of $128.5
million and $153.9 million at December 31, 2001 and 2000, respectively, are
pledged as security on certain of the Company's indebtedness, as described
above.

                                       F-23
<PAGE>

  LETTERS OF CREDIT AND GUARANTEES.

     The Company had aggregate outstanding letters of credit and related types
of guarantees, not reflected in the accompanying consolidated financial
statements, of $62.1 million and $59.7 million at December 31, 2001 and 2000,
respectively.

  SUBSEQUENT EVENT.

     In March 2002, the Company entered into a $250.0 million short-term credit
facility, which was amended and restated in May 2002. The facility will mature
at the earlier of August 31, 2003, or June 16, 2003 if the Veritas transaction
(Note 3) has been terminated prior to that date. The Company must make a
mandatory prepayment of $175.0 million from the future proceeds of any Atlantis
sale (Note 3). The credit facility carries an initial interest rate equal to
LIBOR plus a margin of 0.65%, which margin escalates to 1.0% on June 1, 2002, to
1.5% on August 1, 2002, and to 4.5% on October 1, 2002 until maturity. In the
event that either Standard & Poor's or Moody's downgrades the Company's credit
rating below BBB- or Baa3, respectively, prior to October 1, 2002, the margin
will escalate to 4.5% at the time such downgrade is issued. If any amounts are
outstanding under the credit facility at July 31, 2002 (or earlier in the event
of termination of the Veritas transaction prior to July 31, 2002), the Company
is obligated to use its best endeavors to arrange financing in order to repay
such amounts prior to maturity. Additionally, if the credit facility remains
outstanding at July 1, 2002, the Company will be required to limit any
additional cumulative capital expenditures and multi-client investments to a
maximum of $280.0 million for the period from July 1, 2002 through the maturity
date of the credit facility. The net proceeds from this credit facility were
used to repay the $225.0 million of senior unsecured notes which matured in
March 2002 and for general corporate purposes.

NOTE 11 -- PREFERRED SECURITIES

  GUARANTEED PREFERRED BENEFICIAL INTEREST IN JUNIOR SUBORDINATED DEBT
  SECURITIES.

     In June 1999, the Company entered into a transaction with PGS Trust I (the
"Trust"), a newly formed Delaware statutory business trust and wholly owned
finance subsidiary of the Company, whereby the Trust issued $4.4 million of
common securities to a US subsidiary of the Company, issued $143.8 million of
trust preferred securities to the public and used the proceeds to purchase
$148.2 million of junior subordinated debt securities (the "junior debt
securities") from the Company. The Company used the $138.9 million in net
proceeds received to repay indebtedness outstanding under its revolving bank
credit facility.

     The trust preferred securities consist of 5,750,000 securities which carry
a $25 per security liquidation value and mature on June 30, 2039. The trust
preferred securities represent undivided beneficial interests in the assets of
the Trust, but do not carry general voting rights. The trust preferred
securities carry a 9.625% distribution rate, payable quarterly. The Company's
junior debt securities bear an interest rate of 9.625%, payable quarterly, and
mature on June 30, 2039. Absent any event of default, the Company can defer
interest payments throughout the life of the junior debt securities for up to 20
consecutive quarterly periods, subject to the maturity date and limitations on
certain other transactions during any interest deferral period. In the event
that the Company defers its interest payments on the junior debt securities, the
Trust will defer its distributions on the trust preferred securities.

     The Company may redeem the junior debt securities, in whole or in part, at
any time on or after June 2004. Prior to this time, the Company may redeem all
junior debt securities in the event of certain changes in tax or investment
company law. In the event that the Company redeems any of its junior debt
securities prior to maturity, the Trust must use the redemption proceeds to
redeem, on a pro rata basis, an equivalent amount of its trust preferred
securities and common securities.

     The Company has guaranteed, on a subordinated basis, the trust preferred
securities' distributions to the extent that the Trust has cash available for
those distributions. In the event that the Trust does not have such cash,
holders of the trust preferred securities may directly sue the Company or seek
other

                                       F-24
<PAGE>

remedies against the Company. When considered together, the declaration of trust
of the Trust, the junior debt securities, the indenture under which the junior
debt securities were issued and the Company's guarantee related to the trust
preferred securities constitute a full and unconditional guarantee by the
Company of the Trust's obligations under the trust preferred securities.

     Since a US subsidiary of the Company holds all of the Trust's common
securities, the Company consolidates the Trust. The Trust serves solely as a
finance subsidiary, having no independent assets or operations. The sole assets
of the Trust are the junior debt securities issued by the Company, which have an
aggregate principal amount equal to the aggregate liquidation amount of the
trust preferred securities and the common securities issued by the Trust. The
Trust held the full $148.2 million issue of the junior debt securities at
December 31, 2001 and 2000. The $141.0 million carrying value of the trust
preferred securities at December 31, 2001 reflects issuance costs; the carrying
value will accrete to the $143.8 million redemption value by the first date at
which the Company can redeem the trust preferred securities. During the years
ended December 31, 2001, 2000 and 1999, the Company recorded $14.9 million,
$14.8 million and $7.7 million in financial expense for the minority interest in
income of subsidiaries due on the trust preferred securities.

  MANDATORILY REDEEMABLE CUMULATIVE PREFERRED SUBSIDIARY SECURITIES.

     In April 2001, the Company entered into a securitization transaction
related to a portion of its multi-client marine seismic library. Pursuant to
this transaction, the Company sold the portion of its multi-client marine
seismic library to a bankruptcy remote, special purpose subsidiary incorporated
in Jersey, in exchange for net proceeds of $234.3 million and 100% of the common
securities of the Jersey subsidiary. The Jersey subsidiary funded the $234.3
million in proceeds through the issuance of $240.0 million in mandatorily
redeemable preferred securities to a third party investor (a commercial paper
conduit). The Company used the net proceeds primarily to repay indebtedness
outstanding under its revolving bank credit facility.

     The preferred securities issued by the special purpose subsidiary are
redeemed as applicable multi-client library sales occur, from a portion of the
sales proceeds. The preferred securities carry a floating preferred dividend
rate based on commercial paper rates plus a margin approximating 0.60%.
Dividends are cumulative and payable quarterly. During the year ended December
31, 2001, $77.3 million of the preferred securities were redeemed and the
Company recognized $6.0 million in minority interest expense on the preferred
securities. The preferred shares may be redeemed at any time for an amount equal
to the outstanding preferred securities, accrued preferred dividends and related
expenses. The preferred securities will be redeemed, and the preferred dividends
will be paid, solely through the proceeds received on future sales from the
portion of the multi-client library sold to the Jersey subsidiary. The Company
also has the ability, under certain circumstances, to repurchase portions of
such multi-client library. Upon the occurrence of certain events, the preferred
securities holder has the right to require full and immediate redemption of the
preferred securities. Additionally, under certain circumstances that the Company
believes are remote, the preferred securities holder has the ability to gain
voting control of the Jersey subsidiary. However, the Company has various means
to prevent such a change of control including, but not limited to, redemption of
the preferred securities, preferred securities call options and options to
purchase the data.

     In the event that the Company's credit ratings are downgraded to below BB+
or Ba1 by Standard & Poor's or Moody's, respectively, the Company will be
required to increase by 30% its quarterly redemption of the preferred
securities. If those credit ratings remain for a certain period of time or
deteriorate below BB- or Ba3, respectively, the Company must increase the
quarterly redemption of the preferred securities to an amount equal to 100% of
the actual revenue recognized from the licensing of the data held by the
subsidiary.

     The preferred securities do not entitle the holder to any substantive
participation rights. Since the Company holds all of the Jersey entity's common
securities, the Company consolidates the Jersey entity and reflects the
preferred securities at the minimum redemption value less issuance costs.

                                       F-25
<PAGE>

     The minimum required redemptions (exclusive of the effects of issuance
costs) on the preferred securities are summarized as follows:

<Table>
<Caption>
DECEMBER 31,                                                  (IN THOUSANDS OF DOLLARS)
------------                                                  -------------------------
<S>                                                           <C>
2002........................................................          $ 72,000
2003........................................................            46,080
2004........................................................            32,640
2005........................................................            17,880
2006........................................................               720
                                                                      --------
                                                                      $169,320
                                                                      ========
</Table>

NOTE 12 -- COMMITMENTS AND CONTINGENCIES

  LEASES.

     The Company has operating lease commitments expiring at various dates
through 2014. The Company also has capital lease commitments for seismic vessels
and equipment 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, 2001 are as follows:

<Table>
<Caption>
                                                               OPERATING       CAPITAL
                        DECEMBER 31,                             LEASES         LEASES
                        ------------                          ------------    ----------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>             <C>
2002........................................................    $111,442       $13,141
2003........................................................      66,753        11,171
2004........................................................      42,726         9,187
2005........................................................      33,498         8,824
2006........................................................      21,227         3,269
Thereafter..................................................      21,881        15,274
                                                                --------       -------
          Total.............................................    $297,527        60,866
                                                                ========
  Imputed interest..........................................                    (9,250)
                                                                               -------
Net present value...........................................                    51,616
  Current portion...........................................                    (9,933)
                                                                               -------
          Long-term portion.................................                   $41,683
                                                                               =======
</Table>

     Future minimum payments related to non-cancelable operating leases reflect
$21.4 million and $12.0 million in sub-lease income for 2002 and 2003,
respectively, related to a time-charter of two FPSO shuttle tankers 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,
                                                                   ------------
                                                             (IN THOUSANDS OF DOLLARS)
<S>                                                          <C>
Marine seismic and support vessels.........................          $ 46,630
FPSO shuttle tankers.......................................            58,105
Land seismic equipment.....................................            63,546
Operations computer equipment..............................            51,287
Buildings..................................................            67,745
Fixtures, furniture and fittings...........................            10,214
                                                                     --------
          Total............................................          $297,527
                                                                     ========
</Table>

                                       F-26
<PAGE>

     Rental expense for operating leases, including leases with terms of less
than one year, was $123.1 million, $137.7 million and $133.3 million for the
years ended December 31, 2001, 2000 and 1999, respectively. Rental expense for
operating leases for the year ended December 31, 2001 reflected $13.8 million in
sub-lease income related to a time charter of two FPSO shuttle tankers to a
third party.

     Certain operating leases for land seismic equipment contain extension
options that the Company may exercise in 2002. If these options are exercised,
the leases will be classified as capital leases at that time.

  OTHER.

     The Company has contingent liabilities 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.

NOTE 13 -- INCOME TAXES

     The provision (benefit) for income taxes consists of the following:

<Table>
<Caption>
                                                         YEARS ENDED DECEMBER 31,
                                                      -------------------------------
                                                        2001       2000        1999
                                                      --------   ---------   --------
                                                         (IN THOUSANDS OF DOLLARS)
<S>                                                   <C>        <C>         <C>
Current taxes:
  Norwegian.........................................  $  4,179   $   1,077   $     --
  Foreign...........................................     9,510       4,588      3,492
Deferred taxes:
  Norwegian.........................................   (11,031)   (122,847)   (38,792)
  Foreign...........................................    33,145     (18,153)   (29,925)
                                                      --------   ---------   --------
          Total.....................................  $ 35,803   $(135,335)  $(65,225)
                                                      ========   =========   ========
</Table>

     The net expense (benefit) for the years ended December 31, 2001 and 2000
includes $65.9 million and $3.8 million, respectively, in valuation allowance
charges related to deferred tax assets.

     The Company has evaluated the need for valuation allowances for 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 in jurisdictions other than
Norway due to cumulative losses in recent years in those jurisdictions. Because
of these cumulative losses, the Company has concluded that it was not more
likely than not that the net deferred tax assets in those jurisdictions would be
realized and has recognized the valuation allowances accordingly. However, 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 non-Norwegian deferred tax assets, the Company
will continue to provide 100% valuation allowances on those assets. With regard
to Norwegian net deferred tax assets, the Company has concluded that a valuation
allowance is not required based on management's expectations about the
generation of taxable income in Norway from contracts that are currently in
effect. The Company intends to monitor deferred tax assets generated in Norway
to determine whether taxable income will be sufficient to realize the assets. If
the Company determines that it is more likely than not that the Norwegian
deferred tax assets will not be realized, a valuation allowance will be provided
on the excess of the deferred tax assets over taxable income.

     The net expense (benefit) for the years ended December 31, 2001 and 1999
includes $14.4 million and $15.3 million, respectively, related to the
resolution of uncertainties regarding outstanding tax issues.

     The net benefit for the years ended December 31, 2000 and 1999 includes
($2.6) million and ($8.1) million, respectively, in benefit related to the
cumulative effect of accounting changes.

                                       F-27
<PAGE>

     The provision (benefit) for income taxes differs from the amounts computed
when applying the Norwegian statutory tax rate to income (loss) before income
taxes (inclusive of gross cumulative effect of accounting change) as a result of
the following:

<Table>
<Caption>
                                                         YEARS ENDED DECEMBER 31,
                                                      -------------------------------
                                                        2001       2000        1999
                                                      --------   ---------   --------
                                                         (IN THOUSANDS OF DOLLARS)
<S>                                                   <C>        <C>         <C>
Income (loss) before income taxes:
  Norwegian.........................................  $(47,570)  $(337,706)  $(52,487)
  Foreign...........................................    87,826      (9,110)   (46,554)
                                                      --------   ---------   --------
          Total.....................................    40,256    (346,816))  (99,041)
Norwegian statutory rate............................        28%         28%        28%
                                                      --------   ---------   --------
Provision (benefit) for income taxes at the
  statutory rate....................................    11,272     (97,108)   (27,731)
Increase (reduction) in income taxes from:
  Foreign earnings taxed at other than statutory
     rate...........................................   (40,695)    (11,733)   (34,503)
  Prior year tax assessment.........................      (696)     (1,177)        --
  Unrealized exchange losses........................      (700)    (33,147)    (8,068)
  Permanent items...................................     1,590       2,010      6,166
  Deferred tax assets valuation allowance...........    65,912       3,792         --
  Other.............................................      (880)      2,028     (1,089)
                                                      --------   ---------   --------
          Provision (benefit) for income taxes......  $ 35,803   $(135,335)  $(65,225)
                                                      ========   =========   ========
</Table>

     The temporary differences which generate the Company's deferred tax assets
and liabilities are summarized as follows:

<Table>
<Caption>
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 2001          2000
                                                              -----------   -----------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>           <C>
Property and equipment and long-term assets.................   $  76,408     $  92,979
Tax losses carried forward..................................    (215,817)     (143,502)
Deferred gains..............................................       2,167         3,281
Tax and book revenue and cost of sales......................     (16,974)      (75,582)
Tax credits.................................................      (3,657)       (3,839)
Expenses deductible when paid...............................     (14,159)      (18,412)
Other temporary differences.................................      (2,689)       (1,179)
                                                               ---------     ---------
          Total before valuation allowance..................    (174,721)     (146,254)
                                                               ---------     ---------
Deferred tax assets valuation allowance.....................      69,704         3,792
          Total.............................................    (105,017)     (142,462)
Deferred tax (asset) -- Norwegian...........................    (110,284)      (96,175)
Deferred tax (asset) liability -- Foreign...................       5,267       (46,287)
                                                               ---------     ---------
          Total.............................................   $(105,017)    $(142,462)
                                                               =========     =========
</Table>

     Norwegian tax losses of $576.1 million expire at various dates from 2003
through 2011. Tax losses in the UK, Singapore and Australia totaling $141.6
million carry forward indefinitely. US tax losses of $27.2 million and $10.2
million expire in 2019 and 2021, respectively. US minimum tax credits of $4.0
million carry forward indefinitely.

     It is the Company's current policy that unremitted earnings of certain
international operations, which reflect full provision for non-Norwegian income
taxes, have no provision for Norwegian taxes, as these earnings are expected to
be reinvested indefinitely. The Company has not calculated the tax effect
associated with these unremitted earnings as it is not practicable to so do.

                                       F-28
<PAGE>

     The $15.9 million tax effect related to the reversal of $56.8 million in
contingent liability and goodwill recorded in the acquisition of the FPSO
operations of Awilco ASA was credited directly against deferred tax assets
during the year ended December 31, 2001.

     The tax effect of deductible share issue costs, which have been credited
directly to shareholders' equity, was approximately $0.7 million for the year
ended December 31, 1999. There were no such effects for the years ended December
31, 2001 and 2000.

NOTE 14 -- EARNINGS PER SHARE

     Basic earnings per share and diluted earnings per share for the years ended
December 31, 2000 and 1999 were equal, since both basic and diluted earnings per
share were calculated using the weighted average shares outstanding for the
periods due to the Company's losses. The difference between the Company's 2001
basic earnings per share and diluted earnings per share calculations is
reconciled as follows:

<Table>
<Caption>
                                                           YEAR ENDED DECEMBER 31, 2001
                                                     -----------------------------------------
                                                        INCOME
                                                     AVAILABLE TO      WEIGHTED      PER SHARE
                                                     SHAREHOLDERS   AVERAGE SHARES    AMOUNT
                                                     ------------   --------------   ---------
                                                             (IN THOUSANDS OF DOLLARS,
                                                              EXCEPT FOR SHARE DATA)
<S>                                                  <C>            <C>              <C>
Basic earnings per share...........................     $4,453       102,768,283       $0.04
Share equivalents -- options.......................                       19,772
                                                                     -----------
Diluted earnings per share.........................     $4,453       102,788,055       $0.04
                                                        ======       ===========       =====
</Table>

     Certain options that would have been anti-dilutive to earnings per share
have been excluded from share equivalents.

NOTE 15 -- SHAREHOLDERS' EQUITY

     The retained earnings of the Company, together with additional paid-in
capital, constitute the restricted portion of shareholders' equity and are only
distributable with shareholder approval. Additionally, the terms of certain of
the Company's debt agreements restrict dividend payments. Dividends, if
declared, are payable in Norwegian kroner.

     In July and early August 1999, the Company issued an aggregate of
11,159,500 shares and ADSs in an international public offering. Net proceeds of
$214.1 million were used, together with the net proceeds from $200.0 million in
senior notes, to repay the bank bridge loan facility drawn to finance the
Petrojarl Varg acquisition as well as to repay indebtedness outstanding under
the Company's revolving bank credit facility (Note 10).

NOTE 16 -- SHARE-BASED COMPENSATION

     At December 31, 2001, the Company had share-based compensation plans for
key employees and directors. The employee and director plans authorize the
Company to award options to purchase shares prior to the year 2002. As of
December 31, 2001, options to purchase 9,664,100 and 500,000 shares,
respectively, remained under these authorizations (as defined under Norwegian
law). Options granted from the plans' inceptions to December 31, 2001 totaled
16,462,404 and 816,800 shares, respectively, some of which have been exercised
or were otherwise no longer outstanding at December 31, 2001.

     Under the plans, the exercise price of each award equals the market price
of the Company's shares on the date of grant. The vesting period for the granted
options ranges from approximately three years to approximately three and
one-half years, provided that the recipient is still employed by the Company on
the vesting date. Once vested, the recipient generally has two years within
which to exercise the options; for options granted in June 2000 and forward, the
exercise period is generally three years. Certain option awards are exercisable
only on a specific date. The exercise prices for options granted and outstanding
at

                                       F-29
<PAGE>

December 31, 2001 under both the employee and director option plans ranged from
NOK160 to NOK230 for 2,630,000 options and from NOK103 to NOK150 for 6,005,404
options, with weighted average exercise prices of NOK163 and NOK133 for these
respective ranges. The weighted average remaining contractual lives of
outstanding options approximated eight months and 37 months, respectively, for
the option ranges described above.

     Awards made under the plans become immediately exercisable upon the
occurrence of a change in control of the Company, generally defined to include
certain changes in the board of directors, the acquisition of a certain
percentage of outstanding shares, certain merger transactions and certain
dispositions of all or substantially all of the assets of the Company. Under the
terms of the Company's pending transaction with Veritas (Note 3), each Company
optionee will be offered an option to acquire Caymanco shares in exchange for
the Company options. For each option so exchanged, the options will be
exercisable under the same terms and conditions as the Company's current terms
and conditions, except that each option will be exercisable for a whole number
of Caymanco shares equal to the number of Company shares originally subject to
the option multiplied by the exchange ratio, and the option price will be equal
to the Company's original option price divided by the exchange ratio.

     The Company applies Accounting Principles Board Opinion 25, "Accounting for
Stock Issued to Employees," in accounting for its share-based compensation plans
and has adopted the disclosure-only provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation." Accordingly, no compensation cost has been recognized
under these plans. Had the compensation cost for the Company's share-based
compensation plans been determined based on the fair values of the options
awarded at the grant dates, consistent with the provisions of SFAS No. 123, the
Company's net income (loss) and earnings (loss) per share would have been
reduced to the pro forma amounts indicated below:

<Table>
<Caption>
                                                          YEARS ENDED DECEMBER 31,
                                                       ------------------------------
                                                        2001       2000        1999
                                                       -------   ---------   --------
                                                         (IN THOUSANDS OF DOLLARS,
                                                           EXCEPT FOR SHARE DATA)
<S>                                                    <C>       <C>         <C>
Net income (loss):
  As reported........................................  $ 4,453   $(211,515)  $(33,816)
  Pro forma..........................................   (6,177)   (224,677)   (47,396)
Basic earnings (loss) per share:
  As reported........................................  $  0.04   $   (2.07)  $  (0.36)
  Pro forma..........................................    (0.06)      (2.20)     (0.50)
Diluted earnings (loss) per share:
  As reported........................................  $  0.04   $   (2.07)  $  (0.36)
  Pro forma..........................................    (0.06)      (2.20)     (0.50)
</Table>

     The fair value of each option award on the grant date is estimated using
the Black-Scholes option-pricing model with the following weighted average
assumptions used for grants in 2001, 2000 and 1999, respectively: expected
volatility of 55%, 53% and 52%; risk-free interest rates of 4.23%, 6.52% and
5.8%; and expected lives of 3.4, 4.1 and 3.4 years. (Dividend yield is assumed
to be zero for all plan grants.)

     The effects of applying the fair market value method of accounting in the
above pro forma disclosure may not be indicative of future amounts since
additional awards in future years are anticipated.

                                       F-30
<PAGE>

     A summary of the status of the Company's share-based compensation plans as
of December 31, 2001, 2000 and 1999, and changes during the years then ended, is
summarized as follows:

<Table>
<Caption>
                                                                     DECEMBER 31,
                                            --------------------------------------------------------------
                                                   2001                  2000                  1999
                                            -------------------   -------------------   ------------------
                                                       WEIGHTED              WEIGHTED             WEIGHTED
                                                       AVERAGE               AVERAGE              AVERAGE
                                                       EXERCISE              EXERCISE             EXERCISE
                                            OPTIONS     PRICE     OPTIONS     PRICE     OPTIONS    PRICE
                                            --------   --------   --------   --------   -------   --------
                                                              (IN THOUSANDS OF OPTIONS)
<S>                                         <C>        <C>        <C>        <C>        <C>       <C>
Outstanding at beginning of year..........  10,690.8    NOK135     7,691.2    NOK127    8,388.0    NOK120
Granted...................................     120.0    NOK103     3,926.0    NOK143      335.8    NOK130
Exercised.................................     (98.0)   NOK 75      (738.4)   NOK 90     (909.6)   NOK 68
Forfeited.................................  (2,077.4)   NOK108      (188.0)   NOK140     (123.0)   NOK126
                                            --------    ------    --------    ------    -------    ------
Outstanding at end of year................   8,635.4    NOK142    10,690.8    NOK135    7,691.2    NOK127
                                            ========    ======    ========    ======    =======    ======
Weighted average fair value of options
  granted during year.....................              NOK 44                NOK 69               NOK 56
                                                        ======                ======               ======
</Table>

     As of December 31, 2001, 4,611,404 of the outstanding options were vested
with a weighted average exercise price of NOK143. Exercisable options at
December 31, 2000 and 1999 were 4,762,000 options at a weighted average exercise
price of NOK136 and 2,308,000 options at a weighted average exercise price of
NOK93, respectively.

NOTE 17 -- DERIVATIVE FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

  NOTIONAL AMOUNTS AND CREDIT EXPOSURE OF DERIVATIVE FINANCIAL INSTRUMENTS.

     The notional amounts of the derivative financial instruments summarized
below do not reflect the values exchanged by the parties and, thus, are not a
measure of the Company's exposure. The amounts ultimately exchanged are
calculated on the basis of the notional amounts and the other terms of the
respective derivative financial instruments.

  FOREIGN CURRENCY EXCHANGE RISK MANAGEMENT.

     The Company periodically enters into forward exchange contracts and option
contracts to hedge against foreign currency exchange risks associated with
certain firm commitments and transactions related to property and equipment. The
Company is most sensitive to changes in the Norwegian kroner to US dollar
exchange rates. At December 31, 2001, the Company had approximately $15.0
million of notional forward foreign currency exchange contracts outstanding to
hedge short-term Norwegian kroner and US dollar transactions; these contracts
had a de minimis aggregate fair value. Also at December 31, 2001, the Company
had approximately $17.2 million of notional forward foreign currency exchange
contracts outstanding to hedge US dollar and Brunei dollar transactions during
2002; these contracts had an aggregate fair value of approximately $0.9 million.
There were no such foreign currency exchange contracts outstanding at December
31, 2000.

     During 1998, the Company entered into forward foreign currency exchange
contracts known as tax equalization swaps ("TES") related to its $360.0 million
of senior unsecured notes and its mortgage notes (Note 9). During 1999, the
Company entered into additional TES contracts related to its remaining $1.1
billion in unsecured senior notes (Note 8) and its trust preferred securities
(Note 9). These contracts effectively 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, respectively, in each period on a mark-to-market basis
for Norwegian statutory tax purposes. Although these contracts are economic
hedges, they do not qualify for hedge accounting treatment. As a result, the
periodic adjustments necessary to reflect the fair value of these instruments in
the Company's balance sheet are recognized immediately in the Company's results
of operations. The contracts' aggregate notional

                                       F-31
<PAGE>

values at December 31, 2001 and 2000 were $492.8 million and $682.8 million,
respectively. The TES contracts terminate at various dates through December 2003
and provide for interim settlements between the Company and the counterparty
each December 30. At December 31, 2001, the Company's interim settlement
position was an $11.4 million liability, and the Company carried an additional
liability of $32.5 million to reflect the fair value of the contracts. At
December 31, 2000, the Company's interim settlement position was a $65.2 million
liability (which was paid during 2001), and the Company carried an additional
liability of $26.0 million to reflect the fair value of the contracts. Results
of operations for the years ended December 31, 2001, 2000 and 1999 included
$18.0 million, $61.4 million and $32.8 million, respectively, of fair value
expense (in other expense, net) for these contracts, and tax benefits of $5.7,
$50.3 million and $14.8 million, respectively.

     In April, 2002, the Company terminated three TES contracts with aggregate
notional values of $160.0 million. The Company did not recognize any significant
impact in its results of operations as a result of the termination.

  FAIR VALUES OF FINANCIAL INSTRUMENTS.

     The carrying amounts of cash and cash equivalents, 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. It is not practicable to estimate the value for
the Company's mandatorily redeemable cumulative preferred subsidiary securities
(Note 4), as the future redemptions do not have determinable dates. The carrying
amounts and the estimated fair values of the Company's other financial
instruments are summarized as follows:

<Table>
<Caption>
                                                          DECEMBER 31,
                                       ---------------------------------------------------
                                                 2001                       2000
                                       ------------------------   ------------------------
                                        CARRYING                   CARRYING
                                        AMOUNTS     FAIR VALUES    AMOUNTS     FAIR VALUES
                                       ----------   -----------   ----------   -----------
                                                    (IN THOUSANDS OF DOLLARS)
<S>                                    <C>          <C>           <C>          <C>
Long-term debt, including current
  portion............................  $2,161,310   $1,944,438    $2,170,511   $2,084,703
Trust preferred securities...........     141,000      136,505       140,050      120,750
TES contracts........................      43,909       43,909        91,163       91,163
</Table>

     The following methods and assumptions were used to estimate the fair values
of each class of financial instrument:

     Long-term Debt and Trust Preferred Securities -- The carrying amounts of
the Company's revolving bank credit facility approximate their fair values. The
fair values of the Company's other long-term debt instruments and trust
preferred securities are estimated using quotes obtained from dealers in such
financial instruments.

     TES Contracts -- The fair values of the Company's TES contracts are
estimated based on periodic valuations which are performed by a third party and,
at year-end, the annual settlement.

NOTE 18 -- RETIREMENT PLANS

     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.

                                       F-32
<PAGE>

     Reconciliations of the plans' aggregate projected benefit obligations and
fair values of assets are summarized as follows:

<Table>
<Caption>
                                                                 DECEMBER 31,
                                                              ------------------
                                                               2001       2000
                                                              -------    -------
                                                               (IN THOUSANDS OF
                                                                   DOLLARS)
<S>                                                           <C>        <C>
Change in projected benefit obligations:
  Projected benefit obligations at beginning of year........  $40,304    $33,886
  Service cost..............................................    7,818      6,641
  Interest cost.............................................    2,693      2,042
  Employee contributions....................................    1,118      1,018
  Amendments................................................    4,395      1,061
  Actuarial (gain)/loss, net................................   (7,279)       505
  Benefits paid.............................................   (1,760)    (1,385)
  Exchange rate effects.....................................   (1,178)    (3,464)
                                                              -------    -------
  Projected benefit obligations at end of year..............  $46,111    $40,304
                                                              =======    =======
Change in plan assets:
  Fair value of plan assets at beginning of year............  $29,419    $25,149
  Return on plan assets.....................................   (2,052)     1,515
  Employer contributions....................................    6,143      4,037
  Employee contributions....................................    1,118      1,018
  Amendments................................................    2,559      1,639
  Benefits paid.............................................   (1,760)    (1,385)
  Exchange rate effects.....................................     (856)    (2,554)
                                                              -------    -------
  Fair value of plan assets at end of year..................  $34,571    $29,419
                                                              =======    =======
</Table>

     Plans with accumulated benefit obligations in excess of assets had
aggregate accumulated benefit obligations of $24.7 million and $2.7 million and
aggregate assets of $22.8 million and $2.2 million at December 31, 2001 and
2000, respectively.

     The aggregate funded status of the plans and amounts recognized in the
Company's balance sheets are summarized as follows:

<Table>
<Caption>
                                                                     DECEMBER 31,
                                                              --------------------------
                                                                 2001           2000
                                                              -----------    -----------
                                                              (IN THOUSANDS OF DOLLARS)
<S>                                                           <C>            <C>
Funded status...............................................   $(11,606)      $(10,885)
Unrecognized actuarial loss.................................        302          2,442
Unrecognized prior service cost.............................         22             25
Unrecognized transition obligation..........................        132            138
Additional minimum liability................................        (58)            --
                                                               --------       --------
Net amount recognized as accrued pension cost...............   $(11,208)      $ (8,280)
                                                               ========       ========
</Table>

     The projected benefit obligations have been calculated using the projected
unit credit method. The weighted average discount rate used was 6% for the years
ended December 31, 2001 and 2000 and 7% for the year ended December 31, 1999.
The weighted average expected return on plan assets was 8% for each of the three
years in the period ended December 31, 2001. The weighted average rate of
benefits increase was 4% for the year ended December 31, 2001 and 5% for each of
the years ended December 31, 2000 and 1999.

                                       F-33
<PAGE>

     The aggregate net periodic pension cost for the Company's defined benefit
pension plans is summarized as follows:

<Table>
<Caption>
                                                           YEARS ENDED DECEMBER 31,
                                                         ----------------------------
                                                          2001       2000       1999
                                                         -------    -------    ------
                                                          (IN THOUSANDS OF DOLLARS)
<S>                                                      <C>        <C>        <C>
Components of net periodic pension cost:
  Service cost.........................................  $ 7,818    $ 6,641    $6,602
  Interest cost........................................    2,693      2,042     1,674
  Expected return on plan assets.......................   (2,591)    (2,039)   (1,547)
  Amortization of actuarial loss.......................       26         17       176
  Amortization of prior service cost...................        3          2         3
  Amortization of transition obligation................       14         14        17
                                                         -------    -------    ------
  Net periodic pension cost............................  $ 7,963    $ 6,677    $6,925
                                                         =======    =======    ======
</Table>

     Substantially all employees not eligible for coverage under the defined
benefit plans are eligible to participate in pension 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 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 2001 statutory employee contribution cap of $10,500.
All contributions vest as made. The annual employer matching contribution
recognized by the Company related to the plan was $1.2 million, $1.2 million and
$0.7 million for the years ended December 31, 2001, 2000 and 1999, respectively.
Contributions to the plan by employees for these periods were $3.7 million, $3.8
million and $2.3 million, respectively. Aggregate employer and employee
contributions under the Company's other plans for the years ended December 31,
2001, 2000 and 1999 totaled $4.4 million and $2.7 million (2001), $5.4 million
and $2.6 million (2000) and $5.9 million and $2.5 million (1999).

NOTE 19 -- RELATED PARTY TRANSACTIONS

     At December 31, 2001, 2000 and 1999, 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 50% of the shares in Walther Hervig AS and chartered three
vessels from that company in 2001, 2000 and 1999. Total lease expense recognized
by the Company for 2001, 2000 and 1999 on these vessels was $9.2 million, $8.5
million and $13.9 million, respectively. Remaining lease commitments to these
investees are reflected in the Company's consolidated lease commitments (Note
12).

     At December 31, 2001 and 2000, the Company held 50% of the shares in
Calibre Seismic Company ("CSC"), one of the companies through which the Company
markets its seismic data. The Company had $6.7 million and $11.9 million in
investment in CSC at December 31, 2001 and 2000, respectively, representing
Company-funded costs of seismic data acquisition projects performed for CSC from
1991 to 1995.

     Two members of the Company's senior management each have been granted
options on 50,000 shares in an oil and gas company in exchange for their
services as directors. The Company contributed access to its multi-client
library and a commitment for future geophysical services in exchange for an
equity interest in this oil and gas company. The Company accounts for its
investment in this venture under the equity method of accounting.

NOTE 20 -- SEGMENT AND GEOGRAPHIC INFORMATION

     The Company's services are provided by various separately managed business
units. These business units have been aggregated into two reportable segments,
geophysical services and production services,
                                       F-34
<PAGE>

based on shared economic characteristics and similar long-term performance. The
Company believes that the business units within each reportable segment are
strategically and/or operationally interrelated and provide similar services to
the same customer base. The Company's senior management regularly reviews the
operating results of these two reportable segments in resource allocation
decisions and performance assessment. The geophysical services segment primarily
acquires, processes and markets 3D, 4D and multi-component marine and onshore
seismic data and provides 4D and multi-component reservoir interpretation,
characterization and monitoring services. The production services segment owns
and/or operates FPSOs and other offshore production facilities and provides
production management services for oil and gas companies. The principal markets
for the Company's production services segment are the UK and Norway, while the
geophysical services segment serves a worldwide market. Customers for both
segments are primarily composed of major multi-national, independent and
national or state-owned oil companies. The accounting policies for the segments
are the same as those described in Note 2. The Company's corporate overhead has
been allocated to the segments based on percentage of revenue. Affiliated sales
are made at prices that approximate market value.

     Information by segment is summarized as follows:

<Table>
<Caption>
                                                                   ELIMINATION
                                                                       OF
                                       GEOPHYSICAL    PRODUCTION   AFFILIATED
      YEARS ENDED DECEMBER 31,          SERVICES       SERVICES       SALES          TOTAL
      ------------------------         -----------    ----------   -----------   -------------
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                    <C>            <C>          <C>           <C>
Revenue, unaffiliated companies:
2001.................................  $  594,507     $  458,121          --      $1,052,628
2000.................................     462,604        450,878          --         913,482
1999.................................     419,854        368,306          --         788,160
Revenue, includes affiliates:
2001.................................  $  596,053     $  458,121    $ (1,546)     $1,052,628
2000.................................     472,570        452,095     (11,183)        913,482
1999.................................     426,363        369,166      (7,369)        788,160
Operating profit (loss):
2001.................................  $  121,670     $   84,308          --      $  205,978
2000.................................    (257,415)        25,921          --        (231,494)
1999.................................     (23,396)        62,468          --          39,072
Assets:
2001.................................  $2,115,647     $2,187,159          --      $4,302,806
2000.................................   2,275,565      2,003,141          --       4,278,706
Depreciation and amortization:
2001.................................  $  267,600     $   66,906          --      $  334,506
2000.................................     208,433         55,156          --         263,589
1999.................................     189,335         49,241          --         238,576
Unusual items:
2001.................................  $ (113,445)    $    7,533          --      $ (105,912)
2000.................................     288,595         77,185          --         365,780
1999.................................      82,855          7,000          --          89,855
Interest expense, net:
2001.................................  $   54,174     $   68,070          --      $  122,244
2000.................................      57,191         62,591          --         119,782
1999.................................      40,622         47,636          --          88,258
Additions to long-lived tangible
  assets:
2001.................................  $  256,280     $  213,509          --      $  469,789
2000.................................     285,750         94,008          --         379,758
1999.................................     554,972        451,615          --       1,006,587
</Table>

                                       F-35
<PAGE>

<Table>
<Caption>
                                                                   ELIMINATION
                                                                       OF
                                       GEOPHYSICAL    PRODUCTION   AFFILIATED
      YEARS ENDED DECEMBER 31,          SERVICES       SERVICES       SALES          TOTAL
      ------------------------         -----------    ----------   -----------   -------------
                                                      (IN THOUSANDS OF DOLLARS)
<S>                                    <C>            <C>          <C>           <C>
Investment in equity method
  investees:
2001.................................  $   14,590     $    6,783          --      $   21,373
2000.................................      16,566          2,902          --          19,468
</Table>

     Since the Company provides services to the oil and gas industry worldwide,
a substantial portion of the Company's 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 gas assets) 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.

Information by geographic region is summarized as follows:

<Table>
<Caption>
                                                                                                         ELIMINATION
                                                                                                             OF
                                                                                          MIDDLE EAST/   AFFILIATED
YEARS ENDED DECEMBER 31,    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:
  2001....................  $ 172,780   $  384,742   $189,939     $148,345     $ 75,553     $ 81,269            --     $1,052,628
  2000....................    144,124      402,735    155,561      115,130       39,029       56,903            --        913,482
  1999....................    152,088      381,452    118,788       69,718       61,535        4,579            --        788,160
Revenue, includes
  affiliates:
  2001....................  $ 174,088   $  387,113   $192,116     $148,562     $ 75,553     $ 81,269      $ (6,073)    $1,052,628
  2000....................    150,688      411,417    166,764      117,716       39,029       68,134       (40,266)       913,482
  1999....................    168,237      389,407    138,081       70,942       61,535        8,670       (48,712)       788,160
Operating profit (loss):
  2001....................  $  (9,402)  $   50,781   $154,446     $  5,778     $  8,480     $ (4,105)           --     $  205,978
  2000....................   (161,179)      (6,782)    (2,410)     (39,020)      (8,241)     (13,862)           --       (231,494)
  1999....................    (33,707)      96,098      2,843      (30,053)       4,549         (658)           --         39,072
Long-lived tangible
  assets:
  2001....................  $ 628,662   $1,647,819   $777,995     $139,618     $103,885     $ 73,375            --     $3,371,354
  2000....................    538,900    2,208,465    180,923      120,823      100,177       65,266            --      3,214,554
Depreciation and
  amortization:
  2001....................  $  95,630   $  111,733   $ 60,326     $ 33,696     $ 29,588     $  3,533            --     $  334,506
  2000....................     77,005       98,448     39,319       27,903       16,266        4,648            --        263,589
  1999....................     68,530       93,579     30,489       26,331       17,552        2,095            --        238,576
Capital expenditures:
  2001....................  $   5,258   $   84,760   $148,915     $    208     $    312     $    170            --     $  239,623
  2000....................      7,111       46,443     46,824          360          155       14,324            --        115,217
  1999....................      4,812      608,054     31,320           82          282       23,319            --        667,869
</Table>

     Export sales from Norway to unaffiliated customers did not exceed 10% of
gross revenue for the years ended December 31, 2001, 2000 and 1999.

     For the years ended December 31, 2001 and 2000, two customers accounted for
14% and 11% of our revenue (2001) and 16% and 11% of our revenue (2000); both
customers utilized both geophysical and production services. For the year ended
December 31, 1999, the Company's largest customer accounted for approximately
16% of the Company's revenue, all of which was production services revenue.

                                       F-36
<PAGE>

NOTE 21 -- SUPPLEMENTAL CASH FLOW INFORMATION

     Cash paid during the year includes payments for:

<Table>
<Caption>
                                                          YEARS ENDED DECEMBER 31,
                                                        -----------------------------
                                                          2001       2000      1999
                                                        --------   --------   -------
                                                          (IN THOUSANDS OF DOLLARS)
<S>                                                     <C>        <C>        <C>
Interest, net of capitalized interest.................  $126,705   $120,076   $83,957
Minority interest on trust preferred securities (Note
  11)/ multi-client library securitization (Note
  11).................................................    19,310     13,835     7,225
Income taxes..........................................     1,257      4,505     7,790
</Table>

     The Company entered into capital lease agreements for new equipment
aggregating $41.8 million, $8.5 million and $3.5 million during the years ended
December 31, 2001, 2000 and 1999, respectively.

NOTE 22 -- FINANCIAL EXPENSE, NET

     Financial expense, net, includes the following:

<Table>
<Caption>
                                                        YEARS ENDED DECEMBER 31,
                                                    ---------------------------------
                                                      2001        2000        1999
                                                    ---------   ---------   ---------
                                                        (IN THOUSANDS OF DOLLARS)
<S>                                                 <C>         <C>         <C>
Interest income...................................  $   5,817   $   5,076   $   4,494
Interest expense..................................   (128,061)   (124,858)    (92,752)
Minority interest on trust preferred securities
  (Note 11).......................................    (14,935)    (14,817)     (7,711)
Minority interest on multi-client library
  securitization securities (Note 11).............     (6,000)         --          --
                                                    ---------   ---------   ---------
     Financial expense, net.......................  $(143,179)  $(134,599)  $ (95,969)
                                                    =========   =========   =========
</Table>

NOTE 23 -- UNUSUAL ITEMS

     Unusual items for the year ended December 31, 2001 include a $138.5 million
gain on the sale of the Company's data management business (Note 3).
Additionally, unusual items include $13.2 million in multi-client library
impairment charges, primarily related to onshore surveys in natural gas prone
areas of the US, and $19.4 million in litigation costs and reorganization costs
(including severance for former members of senior management).

     During the year ended December 31, 2000, the Company's geophysical services
did not recover as expected, despite the significant, sustained improvement in
oil and gas prices. As a result of these market conditions, the Company recorded
$166.5 million in impairment charges against its multi-client library; $148.8
million in impairment charges against property, equipment and other assets; and
$50.5 million in contract losses. These charges included $77.2 million related
to the Ramform Banff and certain other production assets.

     During the year ended December 31, 1999, the Company experienced a
significant decrease in the demand for its geophysical services due to the low
price of oil during 1998 and the first half of 1999. As a

                                       F-37
<PAGE>

result of these reduced activity levels, the Company implemented certain
restructuring efforts and recorded charges during the first and third quarters
related to these efforts as summarized below:

<Table>
<Caption>
                                                                    ACCRUED                  ACCRUED
                                                        AMOUNTS    BALANCE AT    AMOUNTS    BALANCE AT
                                                        PAID IN   DECEMBER 31,   PAID IN   DECEMBER 31,
                                         TOTAL CHARGE    1999         1999        2000         2000
                                         ------------   -------   ------------   -------   ------------
                                                           (IN THOUSANDS OF DOLLARS)
<S>                                      <C>            <C>       <C>            <C>       <C>
Cash charges:
  Severance for approximately 500
     employees.........................    $12,685      $ 6,063     $ 6,622      $ 6,622       $ --
  Lease termination, derigging and
     other obligations.................     38,734       28,036      10,698       10,698         --
                                           -------      -------     -------      -------       ----
     Cash charges......................     51,419       34,099      17,320       17,320         --
                                           -------      -------     -------      -------       ----
Non-cash charges -- write-off and
  write-down of property and
  equipment............................     22,535
                                           -------
          Total cash and non-cash
            charges....................    $73,954
                                           =======
</Table>

     The employees whose employment was terminated were primarily field and
support personnel associated with marine, transition zone and land seismic
operations that were removed from service, and employees within the Company's
data processing operations. The Company terminated the employment of
approximately 400 employees as of December 31, 1999 and approximately 100
additional employees during 2000. The amount accrued was based upon the
positions eliminated, length of service and any statutory or legal requirements
applicable within the country where the terminations occurred. The Company paid
all of the costs accrued at December 31, 1999 during 2000.

     The Company accrued $38.7 million for costs to (1) derig marine vessels
removed from operations, (2) settle contractual obligations associated with
leased vessels and equipment removed from service, and (3) accrue for certain
other incremental costs associated with the Company's restructuring efforts.

     The impairment of property and equipment primarily consisted of the
write-off or write-down of geophysical assets that were scrapped, disposed of or
were not expected to benefit future operations, and the write-off of leasehold
improvements associated with leased vessels and equipment removed from service.
The Company also recognized $15.9 million in impairment charges for certain
software, equity investment and other assets.

NOTE 24 -- RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

     The restatements made to the Company's financial statements and related
disclosures are summarized below.

     The Company determined that the value of TES contracts (Note 17) was
incorrectly recorded and presented in its previously issued financial
statements, as only the year-end net settlement value of these instruments was
recognized in the Company's statements of financial position and results of
operations, rather than the fair value of the entire contracts in each reporting
period. The financial statements and related disclosures have been restated to
properly reflect the fair value of these TES contracts as of December 31, 2000
and for the years ended December 31, 2000 and 1999. The restatement also
included a reclassification of the TES contract effects in the Company's
statements of financial position and results of operations. Since the previously
reported settlement values of the tax equalization swap contracts were treated
as an accounting hedge and presented as a net of tax amount within the provision
(benefit) for income taxes, the financial statement effects of these contracts
were reclassified to accrued expenses and other income (expense). The effect of
this restatement was non-cash, net adjustments to previously reported net income
for the years ended December 31, 2000 and 1999 of $2.8 million and ($17.5)
million, respectively.

                                       F-38
<PAGE>

     The Company determined that its financial position and results of
operations as of and for the year ended December 31, 2000 required restatement
to reflect the adoption of SAB No. 101 to the Company's revenue recognition
policy for some types of volume seismic data licensing arrangements and to defer
revenue recognition until the Company has entered into a license agreement for
specific data. The effect of this restatement was a non-cash, net adjustment to
previously reported net income for the year ended December 31, 2000 of ($4.6)
million, including ($6.6) million as the cumulative effect of the change in
accounting principle.

     The Company restated its statements of financial position and results of
operations for fiscal year 2000 related to property and equipment. First, the
Company determined that interest capitalization on its FPSO upgrade projects was
incorrectly calculated and presented in its previously issued financial
statements, as the full value of the capital assets, rather than the incremental
expenditures incurred for the FPSO upgrade projects, was used as the qualifying
asset. The effect of this restatement was a non-cash, net adjustment to
previously reported net income for the year ended December 31, 2000 of ($10.7)
million. Second, the Company determined that the value of two seismic vessels
was incorrectly calculated, which resulted in the miscalculation of the
associated depreciation expense as well as misstatements related to the
Company's multi-client library and amortization, since a portion of the
depreciation recorded for the seismic vessels was capitalized to multi-client
seismic projects. The effect of this restatement was a non-cash, net adjustment
to previously reported net income for the year ended December 31, 2000 of ($3.6)
million.

     The Company determined that a defined benefit plan for UK employees was
incorrectly accounted for on a cash basis, rather than on the proper accrual
basis. The effect of this restatement was a non-cash, net adjustment to
previously reported net income and other comprehensive income for the year ended
December 31, 2000 of ($1.9) million and $0.1 million, respectively.

     The Company determined that it misapplied its minimum amortization policy
for the multi-client library (Note 2). Under this minimum amortization
accounting policy, the Company annually compares the cumulative sales for a
survey to its sales forecast and records a minimum amortization amount if the
survey's cumulative sales are lower than the cumulative forecast through that
date. The Company incorrectly included customer commitments for volume seismic
data licensing arrangements as realized transactions in its analysis of survey
performance, rather than excluding the commitments from cumulative survey sales
until the applicable license periods begin. The effect of this restatement was a
non-cash, net adjustment to previously reported net income for the year ended
December 31, 2000 of ($1.6) million.

     Finally, the Company determined that certain deferred assets were
incorrectly amortized and certain commission/royalty and lease liabilities were
incorrectly accrued. The effects of these restatements were non-cash, net
adjustments to previously reported net income for the year ended December 31,
2000 of ($0.5) million.

     Relative to the tax benefits associated with the restatement adjustments
for the year ended December 31, 2000, the Company determined that a valuation
allowance against deferred tax assets was required due to uncertainties about
its future ability to fully utilize net operating losses in the US and UK. The
effect was a non-cash adjustment of ($3.8) million.

                                       F-39
<PAGE>

     The effects of the restatements on the accompanying financial statements
are included below:

<Table>
<Caption>
                                                      AS OF AND FOR THE YEARS ENDED DECEMBER 31,
                                                -------------------------------------------------------
                                                           2000                         1999
                                                --------------------------   --------------------------
                                                              AS INITIALLY                 AS INITIALLY
                                                AS RESTATED     REPORTED     AS RESTATED     REPORTED
                                                -----------   ------------   -----------   ------------
                                                   (IN THOUSANDS OF DOLLARS, EXCEPT PER SHARE DATA)
<S>                                             <C>           <C>            <C>           <C>
Revenue.......................................  $  913,482     $  906,233    $  788,160     $  788,160
Cost of sales.................................     432,457        423,121       333,060        333,060
Depreciation and amortization.................     263,589        258,484       238,576        238,576
Total operating expenses......................   1,144,976      1,130,000       749,088        749,088
Operating profit (loss).......................    (231,494)      (223,767)       39,072         39,072
Other income (loss), net......................     (32,774)        28,583        (9,144)        23,650
Loss before income taxes......................    (337,716)      (256,966)      (70,976)       (38,182)
Benefit for income taxes......................    (132,756)       (69,392)      (57,137)       (41,890)
Income (loss) before cumulative effect of
  accounting change...........................    (204,960)      (187,574)      (13,839)         3,708
Cumulative effect of accounting change, net of
  tax.........................................      (6,555)            --       (19,977)       (19,997)
Net loss......................................    (211,515)      (187,574)      (33,816)       (16,269)
Basic income (loss) per share before
  cumulative effect of accounting change......       (2.01)         (1.84)        (0.15)          0.04
Cumulative effect of accounting change........       (0.06)            --         (0.21)         (0.21)
Basic loss per share..........................       (2.07)         (1.84)        (0.36)         (0.17)
Diluted income (loss) per share before
  cumulative effect of accounting change......       (2.01)         (1.84)        (0.15)          0.04
Cumulative effect of accounting change........       (0.06)            --         (0.21)         (0.21)
Diluted loss per share........................       (2.07)         (1.84)        (0.36)         (0.17)
Accounts receivable, net......................     242,751        253,410       240,634        240,634
Total current assets..........................     476,961        488,655       398,604        398,604
Multi-client library, net.....................     848,720        847,102       816,423        816,423
Other long-term assets, net...................     333,331        324,273       275,768        267,422
Total assets..................................   4,278,706      4,292,391     4,184,997      4,176,651
Accrued expenses..............................     297,607        203,368       182,441        144,212
Income taxes payable..........................      12,263         77,464         9,805          9,805
Total current liabilities.....................     439,376        410,338       302,720        264,491
Deferred tax liabilities......................      96,260         96,260        71,429         79,852
Total liabilities.............................   2,788,678      2,757,050     2,477,416      2,447,610
Retained earnings.............................      94,410        139,811       305,925        327,385
Total shareholders' equity....................   1,349,978      1,395,291     1,568,417      1,589,877
Total liabilities and shareholders' equity....   4,278,706      4,292,391     4,184,997      4,176,651
</Table>

     The effects of these restatements on the beginning balance of retained
earnings as presented in the consolidated statements of changes in shareholders'
equity was a non-cash, net adjustment of ($3.8) million; this effect was
reflected in the year ended December 31, 1998.

     The pro forma effects of the adoption of SAB No. 101 (discussed above) as
if the adoption had been reflected in fiscal year 1999, rather than as the
cumulative effect of a change in accounting principle as of January 1, 2000, are
presented below:

<Table>
<Caption>
                                                               YEAR ENDED
                                                              DECEMBER 31,
                                                                  1999
                                                              ------------
<S>                                                           <C>
Loss before cumulative effect of accounting change..........    $ (8,558)
Cumulative effect of accounting change, net of tax..........     (19,977)
Net loss....................................................     (28,535)
Basic loss per share before cumulative effect of accounting
  change....................................................       (0.09)
Cumulative effect of accounting change, net of tax..........       (0.21)
Basic loss per share........................................       (0.30)
Diluted loss per share before cumulative effect of
  accounting change.........................................       (0.09)
Cumulative effect of accounting change, net of tax..........       (0.21)
Diluted loss per share......................................       (0.30)
</Table>

                                       F-40
<PAGE>

NOTE 25 -- SUMMARIZED FINANCIAL INFORMATION

  PGS GEOPHYSICAL AS.

     PGS Geophysical AS ("PEXAS"), a Norwegian corporation, is a wholly owned
subsidiary of the Company. PEXAS is the largest geophysical services company
within the PGS group of companies. PEXAS is also the charterer of the Ramform
Explorer and the Ramform Challenger. The Company has fully and unconditionally
guaranteed PEXAS charter obligations in connection with certain debt securities
issued to finance the purchase of these vessels. Summarized financial
information for PEXAS 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 PEXAS 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.

<Table>
<Caption>
                                                                YEARS ENDED DECEMBER 31,
                                                            ---------------------------------
                                                              2001        2000         1999
                                                            --------    ---------    --------
                                                                (IN THOUSANDS OF DOLLARS)
<S>                                                         <C>         <C>          <C>
INCOME STATEMENT DATA
Revenue...................................................  $235,495    $ 200,560    $210,459
Operating loss............................................   (90,505)    (110,983)    (10,924)
Net loss..................................................   (75,146)     (89,640)    (13,151)
BALANCE SHEET DATA
Current assets............................................  $147,679    $ 199,197    $100,165
Noncurrent assets.........................................   174,825      209,784     490,663
Current liabilities.......................................    92,568      102,389      61,116
Noncurrent liabilities....................................   308,002      285,144     425,704
Equity (deficit)..........................................   (78,066)      21,448     104,008
</Table>

  OSLO EXPLORER PLC AND OSLO CHALLENGER PLC.

     Both Oslo Explorer PLC ("Explorer") and Oslo Challenger PLC ("Challenger"),
Isle of Man public limited companies, are wholly owned subsidiaries of the
Company, purchased on April 4, 1997 (Note 10). Explorer and Challenger own the
Ramform Explorer and the Ramform Challenger, respectively, and lease these
vessels to PEXAS pursuant to long-term bareboat charters. Explorer and
Challenger are jointly and severally liable under mortgage notes, 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.

<Table>
<Caption>
                                                                 YEARS ENDED DECEMBER 31,
                                                      -----------------------------------------------
                                                               2001                     2000
                                                      ----------------------   ----------------------
                                                      EXPLORER    CHALLENGER   EXPLORER    CHALLENGER
                                                      --------    ----------   --------    ----------
                                                                 (IN THOUSANDS OF DOLLARS)
<S>                                                   <C>         <C>          <C>         <C>
INCOME STATEMENT DATA
Revenue.............................................  $ 7,182      $ 7,144     $ 7,380      $ 7,341
Net income..........................................    1,609        1,570       1,787        1,749
BALANCE SHEET DATA
Current assets......................................  $    --      $    --     $    --      $    --
Noncurrent assets...................................   74,099       73,906      76,482       76,328
Current liabilities.................................    5,534        5,533       5,231        5,231
Noncurrent liabilities..............................   59,373       59,372      63,668       63,666
Equity..............................................    9,192        9,001       7,583        7,431
</Table>

                                       F-41
<PAGE>

                               INDEX TO EXHIBITS

<Table>
<Caption>
         NUMBER
         ------
<C>                      <S>
           1.1           -- Articles of Association, as amended (English translation)
           2.1           -- Deposit Agreement, dated as of May 25, 1993, among
                            Petroleum Geo-Services ASA (the "Company"), Citibank,
                            N.A., as depositary (the "Depositary"), and all holders
                            from time to time of American Depositary Receipts issued
                            thereunder (incorporated by reference to Exhibit (a)(1)
                            of Post-Effective Amendment No. 1 to the Company's
                            Registration Statement on Form F-6 (Registration No.
                            33-61500))
           2.2           -- First Amendment to Deposit Agreement, dated as of April
                            24, 1997, among the Company, the Depositary and all
                            holders from time to time of American Depositary Receipts
                            issued thereunder (incorporated by reference to Exhibit
                            (a)(2) of the Company's Registration Statement on Form
                            F-6 (Registration No. 333-10856))
           2.3           -- Form of American Depositary Receipt (included in Exhibit
                            2.2)
           2.4           -- Certificate of Trust of PGS Trust I (the "Trust")
                            (incorporated by reference to Exhibit 4.10.1 of the
                            Registration Statement of the Company and the Trust on
                            Form F-3 (Registration Nos. 333-10348 and 333-10348-01))
           2.5           -- Amended and Restated Declaration of Trust of the Trust,
                            dated as of June 22, 1999, among the trustees of the
                            Trust named therein, the Company, as Sponsor, and the
                            holders from time to time of preferred undivided
                            beneficial interests in the assets of the Trust
                            (incorporated by reference to Exhibit 1 of the Company's
                            Report on Form 6-K dated July 12, 1999 (SEC File No.
                            1-14614))
           2.6           -- Indenture, dated as of June 22, 1999, between the Company
                            and Chase Bank of Texas, National Association, as
                            Trustee, in respect of junior subordinated debentures of
                            the Company (incorporated by reference to Exhibit 2 of
                            the Company's Report on Form 6-K dated July 12, 1999 (SEC
                            File No. 1-14614))
           2.7           -- First Supplemental Indenture, dated as of June 22, 1999,
                            between the Company and Chase Bank of Texas, National
                            Association, as Trustee, in respect of 9 5/8% Junior
                            Subordinated Debentures due 2039 of the Company
                            (incorporated by reference to Exhibit 3 of the Company's
                            Report on Form 6-K dated July 12, 1999 (SEC File No.
                            1-14614))
           2.8           -- Form of 9 5/8% Junior Subordinated Debenture due 2039
                            (included in Exhibit 2.7)
           2.9           -- Guarantee Agreement, dated as of June 22, 1999, between
                            the Company and Chase Bank of Texas, National
                            Association, as Guarantee Trustee (incorporated by
                            reference to Exhibit 4 of the Company's Report on Form
                            6-K dated July 12, 1999 (SEC File No. 1-14614))
           2.10          -- Form of Preferred Security (included in Exhibit 2.5)
           2.11          -- Indenture, dated as of April 1, 1998, between the Company
                            and Chase Bank of Texas, National Association, as
                            trustee, in respect of senior debt securities
                            (incorporated by reference to exhibit 2.12 of the
                            Company's Annual Report on Form 20-F for the year ended
                            December 31, 1997 (SEC File No. 1-14614))
           2.12          -- First Supplemental Indenture, dated as of April 1, 1998,
                            between the Company and Chase Bank of Texas, National
                            Association, as trustee, in respect of 6 5/8% Senior
                            Notes due 2008 and 7 1/8% Senior Notes due 2028
                            (incorporated by reference to exhibit 2.13 of the
                            Company's Annual Report on Form 20-F for the year ended
                            December 31, 1997 (SEC File No. 1-14614))
</Table>
<PAGE>

<Table>
<Caption>
         NUMBER
         ------
<C>                      <S>
           2.13          -- Revolving Credit Agreement dated as of September 4, 1998
                            among the Company, Chase Manhattan PLC, as arranger,
                            Chase Manhattan International Limited, as agent, and the
                            financial institutions listed therein (incorporated by
                            reference to exhibit 2.5 of the Company's Annual Report
                            on Form 20-F for the year ended December 31, 1998 (SEC
                            File No. 1-14614))
                         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.
           4.1           -- Employment agreement dated April 27, 2000 between the
                            Company and Michael Mathews (incorporated by reference to
                            Exhibit 4.1 of the Company's Annual Report on Form 20-F
                            for the year ended December 31, 2000 (File No. 1-14614)
                            (the "Form 20-F"))
           4.2           -- Employment agreement dated July 31, 1997 between the
                            Company and Reidar Michaelsen (incorporated by reference
                            to Exhibit 4.2 of the Form 20-F)
           4.3           -- Petroleum Geo-Services ASA Executive Pension Scheme dated
                            August 29, 1996 (incorporated by reference to Exhibit
                            4.13 of the Form 20-F)
           4.4           -- Petroleum Geo-Services ASA 2000 -- Incentive Share Option
                            Plan dated June 23, 2000 (incorporated by reference to
                            Exhibit 4.14 of the Form 20-F)
           4.5           -- Petroleum Geo-Services ASA Non-Employee Director Stock
                            Option Plan dated January 1, 2000 (incorporated by
                            reference to Exhibit 4.15 of the Form 20-F)
           4.6           -- Framework Agreement, dated as of April 26, 2001, among
                            Multi-Klient Invest AS, the Company, PGS Multi-Client
                            Seismic Limited, Compass Finrec P Limited, Westdeutsche
                            Landesbank Girozentrale and Compass Holdings Limited
                            (incorporated by reference to Exhibit 4.16 of the Form
                            20-F)
           4.7           -- Servicing Agreement, dated as of April 26, 2001, among
                            Multi-Klient Invest AS, the Company, PGS Multi-Client
                            Seismic Limited, Compass Finrec P Limited, Westdeutsche
                            Landesbank Girozentrale and Compass Holdings Limited
                            (incorporated by reference to Exhibit 4.17 of the Form
                            20-F)
           4.8           -- Jersey License Agreement, dated as of April 26, 2001,
                            among Multi-Klient Invest AS, the Company, PGS
                            Multi-Client Seismic Limited, Compass Finrec P Limited,
                            Westdeutsche Landesbank Girozentrale and Compass Holdings
                            Limited (incorporated by reference to Exhibit 4.18 of the
                            Form 20-F)
           8             -- Subsidiaries (included in Item 4 of the annual report)
          10.1           -- Consent of Arthur Andersen LLP
          10.2           -- Consent of PricewaterhouseCoopers LLP
          99.1           -- Letter to the Securities and Exchange Commission
                            regarding Arthur Andersen LLP
</Table>