SUBSEA 7 S.A. - SUBCY Annual and Transition Report (foreign private issuer) (20-F) Item 5. Operating and Financial Review and Prospects.

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

About EDGAR Online

The following is an excerpt from a 20-F SEC Filing, filed by STOLT OFFSHORE S A on 5/31/2005.

Next Section

Previous Section

SUBSEA 7 S.A. - 20-F - 20050531 - OPERATING_AND_FINANCIAL_REVIEW

Item 5. Operating and Financial Review and Prospects.

Overview

The Company

We are one of the largest offshore services contractors in the world. We design, procure, build, install and service a range of offshore surface and subsurface infrastructure for the global oil and gas industry. We specialize in creating and applying innovative and efficient solutions in response to the technical complexities faced by offshore oil and gas companies as they explore and develop production fields in increasingly deeper water and more demanding offshore environments.

Commercial and Financial Recovery

In 2004, we experienced a major improvement in our operational and financial performance as compared to recent periods.

During 2003, our new senior management developed and began to implement a new strategy, which included a stronger operational focus on: (i) our capabilities in the design, installation and maintenance of SURF systems in deep water and harsh environments; (ii) Conventional platform and pipeline installation services in shallow water environments where doing so is complementary to our deepwater SURF business; and (iii) subsea IMR services to maintain an ongoing market presence in key deepwater areas and adjacent shallow water environments. In addition, the new management team identified a number of businesses and assets for disposal that were not critical to the success of our refocused operations.

Additionally, we made changes in our personnel, operating structure and business processes. The changes included establishing clear lines of regional accountability within the realigned operating structure, responsibility for project execution, the adoption of revised policies in connection with tendering and contracting practices, changes in management, including the appointment of a Corporate Vice President of Project Controls, as well as regional project control managers to emphasize regional project responsibility and the implementation of new procedures for sales and marketing, project management, marine operations technology and engineering, strategic planning and supply chain management. In addition we realigned our operating structure into five geographical regions.

In the first quarter of fiscal year 2004, we resolved outstanding issues with respect to three major loss-making contracts: we settled disputed claims on the OGGS project in Nigeria; we resolved disputed variation orders with the Burullus Gas Company of Egypt; and we entered into a final settlement of our dispute with Algonquin Gas Transmission Company for claims on the Duke Hubline project. Further, on March 18, 2004, we announced an out-of-court settlement of the patent litigation with Technip. All these settlements were fully accounted for in fiscal year 2003.

On February 18, 2004, we announced the award of a $730 million contract for the development of the Greater Plutonio field located offshore Angola, West Africa. The contract was awarded by BP to a consortium we formed with Technip, and represents the largest contract ever to be awarded to us.

On February 20, 2004, we and our Sonastolt joint venture sold to Oceaneering International, Inc. our ROV drill support business, consisting of a fleet of 44 ROVs and certain ancillary equipment, together with related contracts and employees, for approximately $48 million. The sale realized about $25 million in cash to us after settling the interests of Sonangol, our joint venture partner in Angola, and transaction costs. We received further cash from the joint venture in the form of dividends and loan repayments.

On March 22, 2004, we announced that, in addition to the 2005 Langeled pipelay work scope awarded us in November 2003, the Langeled Group, with Norsk Hydro as operator, had exercised its option to award us the 2006 work scope for the Langeled pipeline, which on completion, will be the longest offshore pipeline in the world.

On May 29, 2004, we sold our wholly-owned welding services subsidiary, Serimer DASA, to Serimer Holdings SAS for an after tax gain of $26.1 million. In the third and fourth quarters of fiscal year 2004, we sold the Seaway Explorer and a number of smaller surplus assets.

The operational improvements during 2004 meant that the third quarter of fiscal year 2004 was our first profitable quarter for over two years. During the fourth quarter of fiscal year 2004, negotiations were completed for the settlement of most of the outstanding variation orders and claims on contracts, notably on the Bonga and Yokri projects.

For the fiscal year ended November 30, 2004, we reported a net profit of $5.1 million. This included an aggregate positive impact of $12.5 million attributable to changes in original estimates on the major projects, a charge of $9.4 million for impairment of tangible fixed assets, a gain on disposal of subsidiaries of $25.2 million, and a gain on the disposal of fixed assets of $4.7 million.

The improved results in 2004 represented a dramatic turnaround from the prior two years.

During fiscal year 2002, we experienced unanticipated operational difficulties related to a number of major projects, and we reported a net loss for the year of $151.9 million. This included an aggregate negative impact of $58.8 million attributable to changes in original estimates on major projects, and a charge of $106.4 million for impairment of goodwill and other intangible assets. For the fiscal year ended November 30, 2003, we reported a net loss of $418.1 million. This included an aggregate negative impact of $216.0 million on net income attributable to changes in original estimates on major projects, and a charge of $176.6 million for impairment of fixed assets.

The most significant components of the operational difficulties occurred on a number of projects, primarily in the AFMED region, first undertaken in earlier periods. In addition to the operational difficulties, during fiscal year 2003 we experienced continued delays in our recovery of amounts owed to us and delayed settlement of claims and variation orders on major projects. These issues had significant adverse effects on our liquidity throughout 2003. They also hindered our ability to maintain compliance with the requirements of our financing agreements. Throughout 2003, we engaged in discussions with our primary lenders, and agreed to amendments to our financing agreements to avoid defaults under those financing agreements. During 2004, we entered into new financing arrangements and raised significant new equity capital to improve our financial position.

New Share Capital Issued

On February 16, 2004, we issued and sold 45.5 million Common Shares (the “Private Placement”), raising gross proceeds of approximately $100 million. This was followed by an issuance of 29.9 million Common Shares (the “Subsequent Issue”) to existing shareholders at the same price as the Private Placement, which generated approximately $65 million in gross proceeds in May 2004. On April 20, 2004, SNSA converted a $50 million

subordinated note owed by us to SNSA into 22.7 million Common Shares (the “Debt Conversion”), thus providing a $215 million increase in shareholders’ equity before deduction of expenses.

The New Bonding Facility and the Intercreditor Deed

On February 12, 2004, we entered into a new $100 million performance bond facility, which provided us with the ability to offer bank guarantees and other forms of surety that are often required in the normal course of business to bid on and win new contracts. In addition, we entered into an intercreditor override and security trust deed, dated February 12, 2004 (the “Intercreditor Deed”), that incorporated changes to and superseded the covenants and security in our then existing financing facilities.

The $350 Million Revolving Credit Facility

By November 8, 2004 our financial situation had improved sufficiently so that we were able to enter into a new $350 million multi-currency revolving credit and guarantee facility with a consortium of banks which now provides the main source of finance for us. This facility, together with existing cash balances, was used to retire all other borrowings, and the $100 million performance bond facility was terminated. The new $350 million facility will be used for general corporate purposes, including the issuance of guarantees to support contract performance obligations and other operating requirements.

The facility provides for revolving loans of up to $175 million during the first three years, up to $150 million for the fourth year, reducing to $125 million for the fifth year, until final maturity at November 8, 2009. The remaining capacity under the $350 million facility is available for bonding with a final maturity no later than May 8, 2011. See “—Description of Indebtedness—The $350 Million Revolving Credit Facility.” The agreement with Cal Dive, on April 12, 2005, includes the sale of vessels which have been used as security for the $350 million revolving credit facility. See “—Subsequent Events.” Upon completion of the sale to Cal Dive, the limit of the $350 million revolving credit facility will be reduced to $313 million unless and until we replace the sold assets with assets of an equivalent value.

Outlook

We were more successful in fiscal year 2004 than in recent years in winning new contracts to replenish our order book, and our backlog at November 30, 2004 stood at $1.8 billion, of which $1.1 billion is expected to be executed in fiscal year 2005. This compares to a backlog at February 17, 2004 of $0.9 billion, of which $0.6 billion was for fiscal year 2004.

Strong global energy demand, together with limited excess production capacity and correspondingly high commodity prices, are driving a sustained improvement in the oil and gas service sector. Consequently we expect steady growth in the core markets in which we operate.

Company History

See Item 4. “Information on the Company—History and Development of Stolt Offshore.”

Business Segments

See Item 4. “Information on the Company—Business Segments.”

Critical Accounting Policies

Our significant accounting policies are described in Note 2 to the Consolidated Financial Statements. The preparation of our financial statements requires management to make estimates and judgments that affect the amounts reported in our financial statements and accompanying notes. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. Management has identified the following policies as critical because they may involve a high degree of judgment and complexity.

Project Accounting—Revenue Recognition and the Use of the “Percentage-of-Completion” Accounting Method

Substantially all of our projects are accounted for using the percentage-of-completion method, which is standard for our industry. Under the percentage-of-completion method, estimated contract revenues are accrued based on the ratio of costs incurred to date to the total estimated costs, taking into account the level of physical completion. Estimated contract losses are recognized in full when determined. Contract revenues and total cost estimates are reviewed and revised periodically as work progresses and as change orders are approved. Adjustments based on the percentage-of-completion are reflected in contract revenues in the reporting period. To the extent that these adjustments result in a reduction or elimination of previously reported contract revenues or costs, we would recognize a charge against current earnings. Such charge may be significant depending on the size of the project or the adjustment. Additional information that enhances and refines the estimating process is often obtained after the balance sheet date but before the issuance of the financial statements. Such late information results in an adjustment of the financial statements unless the events occurring after the balance sheet date are outside the normal exposure and risk aspects of the contract.

The percentage-of-completion method requires us to make reasonably dependable estimates of progress toward completion of contracts and contract costs. As discussed in “—Factors Affecting our Results of Operations—Revision of Estimates on Major Projects,” in fiscal years 2002 and 2003, we experienced frequent and significant deterioration of results as compared with original estimates with respect to results relating to a number of projects, including Conoco CMS3, Bonga, Burullus and OGGS. Although the actual results differed significantly from original estimates on these projects, we do not believe our original estimates were unreliable. Rather, we believe we assess our business risks in a manner that allows us to evaluate the outcomes of our projects for purposes of making reasonably dependable estimates. Nevertheless, our business risks have involved, and will continue to involve, unforeseen difficulties, including weather, economic instability, labor strikes, localized civil unrest, and engineering and logistical changes, particularly in major projects. We do not believe our business is subject to the types of inherent hazards described in AICPA Statement of Position (“SOP”) No. 81-1 “Accounting for Performance of Construction-Type and Certain Production-Type Contracts,” that would indicate that the use of the percentage-of-completion method is not preferable.

If we were unable to make reasonably dependable estimates, we would be obliged to use the “zero-estimate-of-profit” method or the “completed-contract” method. Under the zero-estimate-of-profit method, we would not recognize any profit before a contract is completed. Under the completed-contract method, all costs, revenues and profits are accumulated in the balance sheet accounts until project completion. Under both of these methods, we would not recognize project profits until project completion but would recognize a project loss as soon as the loss became evident. If we are unable to continue to use the percentage-of-completion method of accounting, our earnings may be materially adversely impacted.

Project Accounting—Revenue Recognition on Variation Orders and Claims

A major portion of our revenue is billed under fixed-price contracts. Due to the nature of the services performed, claims and variation orders are commonly billed to the customers in the normal course of business and are recognized as contract revenue where recovery is probable and can be reasonably estimated. In addition, some contracts contain incentive provisions based on performance in relation to established targets, which are recognized in the contract estimates when the targets are achieved. Many of the delays and cost overruns discussed in “—Factors Affecting our Results of Operations—Revisions of Estimates on Major Projects,” were the subject of claims and variation orders. Throughout fiscal years 2003 and 2004 we had significant difficulty resolving these claims and variation orders, and a considerable amount of judgement was required to assess to what extent the customers would accept and pay these. As at November 30, 2004, no revenue relating to unagreed claims or disputed receivables was included in reported turnover or receivables that has not been subsequently collected in full.

Tangible Fixed Assets, Goodwill and Other Intangible Assets

This subject is included under “—Critical Accounting Policies” due to the qualitative factors involved in determining fair values and preparing cash flow projections for assets over which there are impairment issues and because of the large net book value of such assets.

Fixed assets are recorded at cost, and depreciation is recorded on a straight-line basis over the useful lives of the assets, except for ships, which are considered to have a residual value of 10% of the acquisition cost. Management uses its experience to estimate the remaining useful life of an asset, particularly when it has been upgraded.

Goodwill represents the excess of the purchase price over the fair value of net assets acquired in a business combination, and is not subject to amortization. Rather the balance is reviewed for impairment on an annual basis or whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The only goodwill in our balance sheet is $5.3 million in respect of the acquisition of the Paragon Companies. The sale of Paragon in January 2005 supported this goodwill value.

In accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-lived Assets,” tangible fixed assets, and other intangible assets subject to amortization, are required to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for recoverability, we estimate the future cash flows expected to result from the use of the asset and its eventual disposition. If the undiscounted future cash flow is less than the carrying amount of the asset, the asset is deemed impaired. The amount of the impairment is measured as the difference between the carrying value and the fair value of the asset. The fair value is determined either through the use of an external valuation, or by means of an analysis of future cash flows on the basis of expected utilization and daily charge-out rates. Where cash flow forecasts are used, any impairment charge is measured by comparing the carrying value of the asset against the net present value of future cash flows, discounted using our weighted average cost of capital.

Management’s judgment is required to determine the appropriate business assumptions to be used in forecasting future cash flows. When we record an impairment charge, this creates a new cost base for the assets that have been impaired. We have discussed specific impairment charges recorded in “—Results of Operations— Consolidated Results—Impairment of Tangible Fixed Assets.”

In addition, management’s judgment was required in applying the criteria for classifying assets held for sale as specified in paragraph 30 of SFAS No. 144. In particular, management was required to assess whether or not it was probable that the sale would be completed within one year, by carefully evaluating the status of negotiations with potential purchasers of each business and asset. Assets held for sale are valued at the lower of carrying amount and fair value, less the cost to sell. Where fair value less costs to sell is lower than the cost, we record an impairment charge for the difference.

Recognition of Provisions for Contingencies

We, in the ordinary course of business, are subject to various claims, suits and complaints involving customers, subcontractors, employees, tax authorities, etc. Management, in consultation with internal and external advisers, will provide for a contingent loss in the financial statements if information available prior to issuance of the financial statements indicate it is probable that a liability has been incurred at the date of the financial statements and the amount of the loss can be reasonably estimated. In accordance with SFAS No. 5 “Accounting for Contingencies,” as interpreted by FASB Interpretation No. 14 “Reasonable Estimation of the Amount of a Loss,” if we have determined that the reasonable estimate of the loss is a range and that there is no best estimate within the range, we will provide for the lower amount of the range. The provision is subject to uncertainty and no assurance can be given that the amount provided in the financial statements is the amount that

will be ultimately settled. If the provision proves not to be sufficient, our results may be adversely affected. The notable legal claims made against us are discussed fully in Note 26 to the Consolidated Financial Statements and are summarized in “—Legal, Regulatory and Insurance Matters.”

We also provide for warranty costs arising in relation to our long-term contracts if they qualify for recognition in accordance with SFAS No. 5, as detailed above. At the conclusion of each project, an assessment is made of the areas where potential claims may arise under the contract warranty clauses. Where a specific risk is identified and the potential for a claim is assessed as probable, an appropriate warranty provision is recorded. This judgment requires a high level of experience. Warranty provisions are eliminated at the end of the warranty period except where warranty claims are still outstanding.

Income Taxes

We account for income taxes in accordance with SFAS No. 109 “Accounting for Income Taxes,” which requires that deferred tax assets and liabilities be recognized, based on the differences between the financial reporting and tax basis of assets and liabilities and measured by applying enacted tax rates and laws to taxable years in which such differences are expected to reverse. We determine deferred tax assets for each tax paying entity or group of entities that are consolidated for tax purposes. A valuation allowance is established to reduce the amount of the deferred tax asset that we believe, based upon objectively verifiable evidence, is more likely than not to be realized. In determining the valuation allowance we have regard to forecasts of future taxable income, the future reversals of existing temporary taxable differences and whether future tax benefits carried forward in tax returns will ultimately be permitted as tax deductible by the relevant taxing authority. Ultimately we need to generate taxable income in the jurisdiction where we have deferred tax assets. As the estimates and judgments include some degree of uncertainty, changes in the assumptions could require us to adjust valuation allowances.

We operate in many countries and are therefore subject to the jurisdiction of numerous tax authorities as well as cross-border tax treaties concluded between governments. Our operations in these countries are taxed on different bases, including net profit, deemed profit (generally based on the turnover) and withholding taxes based on turnover. We determine our tax provision based on our interpretation of enacted tax laws and existing practices, and use assumptions regarding the tax deductibility of items and the recognition of revenue. Changes in these assumptions could have an impact on the amount of income taxes that we provide for in any given year.

In the normal course of our business our tax filings become subject to enquiry and audit by the tax authorities in jurisdictions where we have operations. The enquiries may result in additional assessments to taxation, we aim to resolve through an administrative process with tax authorities and failing that through a judicial process. Forecasting the ultimate outcome includes some uncertainty.

Management has established internal procedures to regularly review the status of disputed tax assessments and utilizes such information to determine the range of likely outcomes and establish tax provisions for the most probable outcome. Notwithstanding this, the possibility exists that the amounts of taxes finally agreed could differ from that which has been accrued. In addition we have, under the guidance in SFAS No. 5 “Accounting for Contingencies” provided for taxes in situations where tax assessments have not been received, but it is probable that the tax ultimately payable will be in excess of that filed in tax returns. Such instances can arise where the auditors or representatives of the local tax authorities disagree with our interpretation of the applicable taxation law and practice.

Accounting for Derivatives

It is our policy to apply hedge accounting in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” when accounting for derivative instruments such as forward currency contracts and currency swaps. This standard requires gains and losses resulting from changes in the market value of derivative contracts to be deferred in our accounts until such time as the underlying transaction affects

earnings. It also requires management to ensure that adequate documentation is in place at the inception of the hedging contract to support its treatment as an effective hedge for an underlying business transaction. The judgment of management is required to estimate the fair value of instruments that have no quoted market prices, and forecast the probable date and value of the underlying transaction.

During August 2003, we closed out the majority of our foreign exchange positions to ensure that we had sufficient liquidity to fund our operations and to provide for a potentially protracted period of negotiation with certain major customers regarding settlement of claims and variation orders. We realized a $28.2 million gain when these positions were closed. This gain was deferred in “Other Comprehensive Income” in the Consolidated Statements of Shareholders’ Equity and has been fully released to the results of operations in line with the original underlying transactions for which the hedges were designated during fiscal years 2003 and 2004. See Note 27 to the Consolidated Financial Statements. In order to mitigate currency exposures during the period between August 2003 and November 2004 when forward contracts were not available from commercial banks due to our financial position, a number of projects were negotiated to allow us to be paid in currencies matching the anticipated outflows on the contract. Where appropriate, any embedded derivatives identified have been accounted for in compliance with SFAS No. 133.

Employee Stock Plans

We account for our stock options using the intrinsic-value method prescribed in Accounting Principles Board Opinion No. 25 “Accounting for Stock Issued to Employees” (“APB No. 25”). Accordingly, compensation cost of stock options is measured as the excess, if any, of the quoted market price of our stock at the measurement date over the option exercise price and is charged to operations over the vesting period. For plans where the measurement date occurs after the grant date, referred to as variable plans, compensation cost is remeasured on the basis of the current market value of our stock at the end of each reporting period. We recognize compensation expense for variable plans with performance conditions if achievement of those conditions becomes probable. As required by SFAS No. 123 “Accounting for Stock-Based Compensation” (“SFAS No. 123”), we have included in these financial statements the required pro forma disclosures as if the fair-value method of accounting had been applied.

As explained under “—Selling, General, and Administrative (“SG&A”) Expenses” below, in 2004 we have put in place a Key Staff Retention Plan (“KSRP”) to secure the services of certain senior executives through to the first quarter of fiscal year 2007. This plan is a variable plan as defined in APB No.25, and provides for deferred compensation as a combination of cash and performance-based share options, linked to the attainment of a number of strategic and financial objectives for each of the fiscal years 2004, 2005 and 2006. The objectives fixed in the plan, and agreed by the compensation committee of our board of directors, include targets for net profit, management team retention, bonding lines, internal controls over accounting and audit, business growth and restructuring.

We have accrued for the proportion of compensation expense relating to the service period completed to date. Total expected compensation for the three-year plan was calculated taking into account the probability of the performance conditions being met over the period of the plan. Management’s judgment is required to determine these probabilities.

Factors Affecting Our Results of Operations

Business Environment

The market for our services depends upon the success of exploration and the level of investment in offshore exploration and production by the major oil companies. Such investment is cyclical in nature. Following a period of increasing oil prices in recent years, there has been a progressive increase in investment in offshore exploration and production by the major oil companies and we expect to see a continued expansion of demand in fiscal year 2005 for its services, with this trend continuing over the next few years. This trend is evident in the high numbers of invitations to tender received by us, as well as the increasing level of our order backlog.

Tendering Strategy

We were less successful in fiscal year 2003 than in previous years in winning new contracts to replenish our order book, which resulted in a reduction of 16% in revenue in fiscal year 2004 as compared to 2003. This is partly attributable to the more stringent tendering practices adopted in fiscal year 2003 as described in “—Revisions of Estimates on Major Projects” below, as well as other competitive factors.

Seasonality

Over the past three years, a significant portion of our revenue has been generated from work performed in the North Sea and North America. Adverse weather conditions during the winter months in these regions usually result in low levels of activity, although this is less apparent than in the past due to technological advances. Further, in waters offshore West Africa, where optimal weather conditions exist from October to April, most offshore operations are scheduled for that period. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters. Additionally, during certain periods of the year, we may be affected by delays caused by adverse weather conditions such as hurricanes or tropical storms in the Gulf of Mexico. During periods of curtailed activity due to adverse weather conditions, we continue to incur operating expenses, but our revenues from operations are deferred.

Ship Utilization

Our results are materially affected by our ability to optimize the utilization of our ships in order to earn revenues. The following table sets forth the average ship utilization by year for our fleets of dynamically positioned deepwater and heavy construction ships, light construction and survey ships, and trunkline barges and anchor ships. The utilization rate is calculated by dividing the total number of days for which the ships were engaged in project-related work during a year by 350 days, expressed as a percentage. The remaining 15 days are attributable to routine maintenance.

The utilization of deepwater and heavy construction ships is the most significant in terms of impact on our performance. Utilization of these ships increased in 2004 primarily as a result of two factors: the Seaway Explorer , which had only 72% utilization during fiscal year 2003, was sold in fiscal year 2004, and the Discovery had 100% utilization during fiscal year 2004 due to a large volume of activity in West Africa.

The utilization of light construction and survey ships has improved significantly since fiscal year 2003. This is attributable to the fact that two vessels with low utilization rates during fiscal year 2003, the Seaway Pioneer and the Seaway Rover, were sold during fiscal year 2004 and the fact that the Seaway Legend had 100% utilization in fiscal year 2004 as compared to 54% utilization during fiscal year 2003.

Trunkline barges’ and anchor ships’ utilization declined during fiscal year 2004 because:

•

The LB 200 was not utilized during fiscal year 2004 as compared to 75 days of utilization during fiscal year 2003. The barge was in dry-dock in preparation for a large quantity of work in hand on the Langeled project for fiscal years 2005 and 2006;

•

The DLB 801 had only 104 days of utilization during fiscal year 2004 as compared to 200 days during fiscal year 2003. This was partially attributable to the dry-docking necessitated by the repairs to the stinger (the structure that hangs off the bow of the ship and supports the pipe being laid) following an operational incident in August 2004;

•

Activity for the cargo barges in West Africa was reduced because of timing differences where barges released from projects were not immediately required on subsequent projects; and

•

The Annette was sold in January 2004.

There was a progressive decline in utilization during the three years prior to fiscal year 2004, which we reflected in the impairment charges recorded in the fourth quarter of fiscal year 2003, and that was addressed by the ship disposal program. The general improvement in 2004 utilization reflects the success of this program.

During fiscal year 2005, we expect the utilization rates for trunkline barges and anchor ships to show a slight decline. While the LB 200 will be actively deployed during fiscal year 2005, the utilization of cargo barges in West Africa is expected to continue to decline. The deepwater and heavy construction ship utilization during fiscal year 2005 is also expected to be lower, mainly because the Seaway Condor and the Seaway Harrier are scheduled for dry-docking during fiscal year 2005. Light construction and survey utilization is expected to be lower during fiscal year 2005 due to the Seaway Legend having less work compared to fiscal year 2004.

Ship Scheduling

Our performance can be adversely affected by conflicts in the scheduled utilization of our key ships and barges. These can be caused by delays in releasing ships from projects on schedule due to additional client requirements, overruns and breakdowns. Conflicts can also arise from commercial decisions concerning the utilization of assets after work has been tendered and contracted for. The requirement to substitute ships or barges can adversely affect the results of the projects concerned.

Maintenance and Reliability of Assets

The successful execution of contracts requires a high degree of reliability of our ships, barges and equipment. Breakdowns not only add to the costs of executing a project, but they can also delay the completion of subsequent contracts, which are scheduled to utilize the same assets. We operate a scheduled maintenance program in order to keep all assets in good working order, but despite this breakdowns can occur. In August 2004, an equipment failure involving the stinger of the DLB 801 resulted in significant increased costs and exposure to liquidated damages, both on the barge’s current project (Angostura) and subsequent work. Another area of project performance that can affect results is slower than expected pipelaying rates, as experienced recently by the Seaway Polaris on the Bonga project.

Revisions of Estimates on Major Projects

During the course of major projects, adjustments to the original estimates of the total contract revenue, total contract cost, or extent of progress toward completion, are often required as the work progresses under the contract, and as experience is gained, even though the scope of work required under the contract may not change. These revisions to estimates will not result in restating amounts in previous periods, as they are continuous and characteristic of the process.

We revise our estimates monthly on the basis of project status reports, which include an updated forecast of the cost to complete each project. Additional information that enhances and refines the estimation process is

often obtained after the balance sheet date but before the issuance of the audited financial statements. Such information will be reflected in the audited financial statements, unless the events occurring after the balance sheet date are outside the normal exposure and risk aspects of the contract.

In fiscal year 2004, there was a positive impact of $12.5 million attributable to revisions of estimates on major projects, as compared to a $216.0 million negative impact in fiscal year 2003 and a negative impact of $58.8 million in fiscal year 2002. There were improvements on a large number of projects, which were partially offset by negative revisions to estimates in connection with two major projects, which are included among the significant projects discussed below:

•

$32.3 million of losses were recorded during the third and fourth quarters of 2004 on the $56.0 million lump sum Conventional project offshore Trinidad and Tobago (NAMEX region) for BHP Billiton (the “Angostura project”). The offshore phase of the project started in April 2004, and the project was scheduled to be completed in the fourth quarter of 2004. However, due to an equipment failure in August 2004 involving the stinger on the DLB 801 , the project was significantly delayed. The delays resulted in cost overruns for subcontractors, additional ship and equipment costs, and potential enforcement of liquidated damages of $5.1 million payable by us to our customer, due to the delays in the project schedule. These delays meant that the work had to be performed when the weather offshore Trinidad was particularly severe, which caused additional delays and slower production than normal. The project was 15% complete as at November 30, 2003 and 74% complete as at November 30, 2004;

•

$12.9 million of losses were reported in 2004 on the $240.0 million lump sum Conventional project offshore Angola (AFMED region) for Chevron Texaco (the “Sanha Bomboco project”). In the second quarter of fiscal year 2004, we recognized losses due to unanticipated additional costs for hook-up and commissioning. These additional costs were only partly offset by settlements of variation orders, claims and milestone payments in the fourth quarter of fiscal year 2004. Offshore operations were completed in the fourth quarter of fiscal year 2004. As at November 30, 2003 the project was 72% complete, and as at November 30, 2004 it was 99% complete. We also recorded a $41.5 million negative revision to estimated costs on this project in fiscal year 2003;

•

$13.7 million of improvements were reported in 2004 on the $125.0 million lump sum Conventional project (the “Yokri project”) offshore Nigeria (AFMED region), executed jointly with a local partner for Shell Petroleum Development Company (“SPDC”), acting on behalf of itself and partners, including the Nigerian National Oil Company. The improvement was mainly due to settlement of variation orders and claims in the fourth quarter of fiscal year 2004. This project was 87% complete as at November 30, 2003 and 96% complete as at November 30, 2004;

•

$11.6 million of improvements were reported in 2004 on the $55.0 million lump sum SURF project offshore Norway (NEC region) for Total (the “Skirne Byggve project”). In the second and third quarters of fiscal year 2004, we released provisions made in fiscal year 2003 for rectification of technical problems encountered due to lower expenses than expected. As at November 30, 2003, the project was 99% complete, and as at November 30, 2004, it was 100% complete. We also recorded a $13.1 million negative revision to estimated costs on this project in fiscal year 2003;

•

$6.7 million of improvements were reported in 2004 on the $60.0 million lump sum SURF project offshore United Kingdom (NEC region) for ConocoPhillips (UK) Limited (the “Conoco CMS3 project”). In the third quarter of fiscal year 2004, we received settlement of claims dating back from 2002. As at November 30, 2003, the project was 99% complete, and as at November 30, 2004, it was 100% complete. We also recorded $4.8 million and $0.8 million negative revisions to estimated costs on this project in fiscal years 2002 and 2003 respectively; and

•

$12.9 million in favorable revisions were recorded on the three other Legacy Projects, namely the Burullus, Bonga and OGGS projects. These improvements were the result of negotiations with the clients to close out and settle outstanding variation orders and claims, most of them in the last quarter of fiscal year 2004. Burullus and OGGS were physically completed in 2003, while the Bonga project was 93% complete overall as at November 30, 2003, and the operational offshore phase was 100% complete

as at November 30, 2004. We recorded a total of $148.8 million of negative revisions on these projects during fiscal year 2003, including $67.8 million on the Bonga project, $51.7 million on the Burullus project and $29.3 million on the OGGS project.

To minimize the potential for future negative revisions such as those defined above, we have modified our estimating, tendering and contracting procedures to reduce the amount of unanticipated costs and improve our ability to recover costs from our customers. Greater selectivity is exercised in choosing which tenders to respond to, and a thorough analysis of the commercial and operational risks as well as a detailed tender budget is prepared to facilitate the decision to tender. Careful consideration is given to vessel schedule conflicts and to the current backlog to ensure we have sufficient resources to perform our obligations.

Under these revised procedures, when a target project is identified by our regional marketing staff, the decision to prepare and submit a competitive bid is taken by our management in accordance with delegated authority limits. We prepare cost estimates on the basis of a detailed standard costing manual, and the selling price and contract terms are based on our minimum commercial standards and market conditions. Before the tender package is submitted to the client, we undertake a detailed review of the project. This review is performed by a dedicated tender team comprised of our regional or Group functional departments including technical, legal and finance. Major project tenders are also subject to approval by our senior management, and very large tenders are subject to approval by the Chief Operating Officer, the Chief Executive Officer or our Board of Directors. The information required to be contained in the internal review packages is uniform across the group to allow management to consistently weigh the risks and benefits of tenders for various projects. We have established a separate estimating department in the AFMED region to centralize the expertise in making reasonably dependable estimates of contract revenues and contract costs.

Our policy is not to undertake variations to work scope without prior agreement of scope, schedule and price. The tender board for each tender decides whether or not to deviate from this policy.

Businesses and Assets Offered for Sale

As a part of our new strategic focus, in fiscal year 2003 we identified a number of assets and businesses which we no longer considered essential to be owned or performed by us to execute core operations. We commenced a divestment program in 2003, and the majority of the significant disposals were completed by the first quarter of 2005.

The business and assets which were offered for sale as at November 30, 2004 are described below:

•

Paragon Engineering Services, Inc. located in the U.S.: Our interest in this engineering business, which was acquired in fiscal year 2001, was sold effective January 19, 2005 to a subsidiary of AMEC plc., resulting in a gain of $2.1 million;

•

National Hyperbaric Centre in Aberdeen, Scotland: This center provides facilities for hydrostatic testing, saturation systems and decompression chambers. We sold the center on December 2, 2004 for proceeds of $2.3 million. This resulted in a gain of $1.3 million. We intend to continue contracting for the center’s services as necessary;

•

The property at Handil, East Kalimantan, Indonesia: This property is used as an operations base and comprises land, buildings and certain equipment and was previously operated by PT Komaritim. As part of the agreement, we are entitled to use certain areas free of charge until January 2008. The Handil property was sold on January 10, 2005 to PT Meindo with proceeds of $1.8 million, resulting in a gain of approximately $0.9 million; and

•

ROV—Scorpio 20, located in Scotland: We sold this ROV on February 2, 2005 with proceeds of $0.6 million, for no gain or loss.

Certain of our trenching and ploughing assets have been identified for disposal because of underutilization. Negotiations with a prospective buyer are ongoing and we expect a sale will be concluded later in fiscal year 2005.

Exchange Rates

We report our financial results in U.S. dollars. We have foreign currency denominated expenses, assets and liabilities. As a consequence, movements in exchange rates can affect our profitability, the comparability of our results between periods and the carrying value of its assets and liabilities. Our major foreign currency exposures are to the Euro, British pound sterling and Norwegian kroner.

When we incur expenses that are not denominated in the same currency as the related revenues, foreign exchange rate fluctuations could adversely affect its profitability. The majority of our net operating expenses are denominated in the functional currency of the individual operating subsidiaries. The U.S. dollar is the functional currency of the most significant subsidiaries within the NAMEX, SAM and AME regions. In the AFMED and NEC regions, the functional currencies are the Euro, Norwegian kroner, Canadian dollar, U.S. dollar and the British pound sterling. Our exposure to currency rate fluctuations results from its net investments in foreign subsidiaries, primarily in the United Kingdom, Norway, France and Brazil, and from our share of the local currency earnings in our operations in the AFMED and NEC regions. We are also exposed to fluctuations in several other currencies resulting from operating expenditures and significant one-off, non project related transactions such as capital expenditures. With the exception of the AFMED region, and to a lesser extent the NEC region, our operating expenses are generally denominated in the same currency as associated revenues, thereby mitigating the impact of exchange rate movements on operating profit. Where revenues are in different currencies from the related expenditures, our policy is to use derivative instruments to hedge the foreign exchange exposure. See “—Critical Accounting Policies—Accounting for Derivatives” and Item 11. “Quantitative and Qualitative Disclosures about Market Risk.” This was not possible in most of fiscal year 2004, due to the unavailability of the necessary credit facilities.

In addition, even where revenues and expenses are matched, we must translate non-U.S. dollar denominated results of operations, assets and liabilities to U.S. dollars to prepare our consolidated financial statements. To do so, balance sheet items are translated into U.S. dollars using the relevant exchange rate at the fiscal year-end for assets and liabilities, and income statement and cash flow items are translated using exchange rates which approximate the average exchange rate during the relevant period. Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect our reported results of operations and the value of assets and liabilities in our consolidated balance sheets even if our results of operations or the value of those assets and liabilities has not changed in their original currency.

As at November 30, 2004, we did not hold a significant number of derivative instruments as foreign exchange lines were in the process of being renegotiated following the refinancing of our existing credit facilities in November 2004. As a result, we had a significant exposure to future foreign exchange fluctuations, as discussed in Item 11. “Quantitative and Qualitative Disclosures about Market Risk—Foreign Exchange Risk Management.” However, trading lines have now been made available to us and in December 2004 we hedged a significant part of our foreign exchange exposures for the following 12 months. In addition, part of our forecasted exposure in Euro for a further 12 months has been hedged.

Impairment Charges

We recognized aggregate impairment charges of $9.4 million in fiscal year 2004 in respect of our tangible fixed assets. As discussed in “—Results of Operations—Consolidated Results—Impairment of Tangible Fixed Assets” below, the charge in fiscal year 2003 was $176.6 million.

Results of Operations

Identification of Major Projects


Project Name		Description
Amenam II		A lump sum Conventional project offshore Nigeria (AFMED region), to be executed during 2004 to 2006 for Total Nigeria/Elf Petroleum Nigeria Ltd.

Angostura		A lump sum Conventional project offshore Trinidad and Tobago (NAMEX region), to be executed during 2003 to 2005 for BHP Billiton.

Arthur		A lump sum SURF project offshore United Kingdom (NEC region), executed during 2004 for Mobil North Sea Ltd.

Benguela Belize		A lump sum Conventional project offshore Angola (AFMED region), to be executed during 2003 to 2005 for Chevron Texaco Overseas Petroleum

Bonga		A lump sum SURF project offshore Nigeria (AFMED region), executed during 2001 to 2004 for Shell Nigeria (“SNEPCO”).

Burullus		A lump sum SURF project offshore Egypt (AFMED region), executed during 2001 to 2003 for the Burullus Gas Company.

Casino		A lump sum SURF project offshore Australia (AME region), to be executed during 2005 to 2006 for Santos Ltd.
Clair		A lump sum SURF project offshore United Kingdom (NEC region), executed during 2004 for BP Exploration Operating Company Limited.

Conoco CMS3		A lump sum SURF project offshore United Kingdom (NEC region), executed during 2001 to 2003 for ConocoPhillips (UK) Ltd.

Dolphin Deep		A lump sum Conventional project offshore Trinidad and Tobago (NAMEX region), to be executed during 2004 to 2005 for BG International Limited.

Draugen		A day-rate IMR project offshore Norway (NEC region), executed during the period 1993 to 2004 for A/S Norske Shell.

Duke Hubline		A combined lump sum and day-rate Conventional project in the United States (NAMEX region), executed during 2002 to 2003 for Algonquin Gas Transmission Company, a subsidiary of Duke Energy Field Services LLC.

Endeavour		A lump sum SURF project offshore United Kingdom (NEC region), executed during 2003 and 2004 for BP Exploration Operating Company Limited.

Erha		A lump sum SURF project offshore Nigeria (AFMED region), to be executed during 2002 to 2006 for ExxonMobil Nigeria.

Girassol		A lump sum SURF project offshore Angola (AFMED region), executed during 1998 to 2003 for a consortium led by Total Angola. This project was performed as a joint venture with Saipem S.A.

Greater Plutonio		A lump sum SURF project to be executed during 2004 to 2007 for BP Angola BV. This project involves the engineering, procurement, fabrication, and installation of umbilicals, risers and flowlines for the development of Bloc 18 offshore Angola (AFMED region).

Langeled		A lump sum Trunkline project offshore Norway (NEC region), to be executed during 2004 to 2006 for Statoil. This project involves the laying of a 900 km large diameter trunkline from the Ormen Lange field in the Norwegian sector of the North Sea to the east coast of southern United Kingdom.


Project Name		Description

Legacy Projects		The term “Legacy Projects” is used to identify a series of loss-making projects contracted for before the change of management in 2003. It refers to the Burullus, OGGS, Bonga, Sanha Bomboco, Yokri and Duke Hubline projects.

NGC-Bud		A lump sum Conventional project offshore Trinidad and Tobago (NAMEX region), to be executed during 2004 to 2005 for NGC.

OGGS		A lump sum Conventional offshore gas gathering system project offshore Nigeria (AFMED region), executed during 2002 to 2004 for Shell Petroleum Development Company of Nigeria Limited (“SPDC-Nigeria”), acting on behalf of itself and partners, including the Nigerian National Oil Company.

Sakhalin		A lump sum SURF project offshore Russia (AME region), to be executed during 2004 to 2005 for Nippon Steel Corporation.

Sanha Bomboco		A lump sum Conventional project offshore Angola (AFMED region), executed during 2002 to 2004 for Chevron Texaco led by Cabinda Gulf Oil Company.

Skirne Byggve		A lump sum SURF project offshore Norway (NEC region), executed during 2002 to 2003 for Total.

Vigdis Extension		A lump sum SURF project offshore Norway (NEC region), executed during 2002 to 2003 for Statoil and Norsk Hydro.

Yokri		A lump sum Conventional project offshore Nigeria (AFMED region), executed during 2001 to 2004 jointly with a local partner for SPDC-Nigeria, acting on behalf of itself and partners, including the Nigerian National Oil Company.

Business Segment Results

The following tables show annual net operating revenue, operating expense and net income (loss) before tax (after minority interests) for each of our business segments for the past three fiscal years.


For the year ended November 30, (in millions)	2004	%	2003	%	2002	%
	$		$		$
Net operating revenue
AFMED	536.0	43.2	673.8	45.4	702.7	48.9
NEC	341.7	27.5	387.6	26.2	335.6	23.3
NAMEX	170.6	13.7	200.6	13.5	190.5	13.3
SAM	55.0	4.4	56.0	3.8	52.0	3.6
AME	31.9	2.6	26.8	1.8	25.7	1.8
Corporate	106.7	8.6	137.5	9.3	131.0	9.1

Total	1,241.9	100.0	1,482.3	100.0	1,437.5	100.0


For the year ended November 30, (in millions)	2004	%	2003	%	2002	%
	$		$		$
Operating expense
AFMED	477.8	42.5	839.8	53.7	681.9	49.7
NEC	287.2	25.4	343.0	21.9	307.2	22.4
NAMEX	213.7	18.9	208.9	13.3	193.0	14.0
SAM	41.0	3.6	34.6	2.2	40.5	2.9
AME	26.4	2.3	26.8	1.7	23.6	1.7
Corporate	82.9	7.3	113.5	7.2	128.2	9.3

Total	1,129.0	100.0	1,566.5	100.0	1,374.4	100.0


For the year ended November 30, (in millions)	2004		2003		2002
	$		$		$
Net income (loss) before tax
(after minority interests)
AFMED	27.0		(285.2	)	(36.6	)
NEC	46.1		23.1		10.9
NAMEX	(49.3	)	(32.3	)	(116.0	)
SAM	11.3		18.2		5.5
AME	2.5		(6.5	)	(3.4	)
Corporate	(23.3	)	(136.0	)	(4.1	)

Total	14.3		(418.7	)	(143.7	)

Africa and the Mediterranean Region (AFMED)

Net Operating Revenue

AFMED’s net operating revenue decreased in fiscal year 2004 by $137.8 million to $536.0 million. The reduction is mainly due to completion of the OGGS project for SPDC and the Girassol project for Total Angola, which were not replaced by contracts of similar size. This was partly due to a decision taken in 2003 to reduce the region’s workload to a level more aligned to its capacity in terms of assets and other resources. The main drivers for the AFMED revenue were the Bonga project for SNEPCO, Sanha Bomboco and Benguela Belize for Chevron Texaco, Erha for Exxon Mobil and Amenam II for Total Nigeria/Elf Petroleum Nigeria Ltd., generating 73% of the revenues for fiscal year 2004. From May 31, 2004, the Sonamet and Sonastolt joint ventures were consolidated and accounted for $33.6 million or 7.5% of AFMED’s revenues for the second half of the fiscal year. The offshore phase of each of the Bonga and Yokri projects was completed in the last quarter of fiscal year 2004, and significant additional revenue was recognized upon the settlement of variation orders and claims on these contracts. Net operating revenue in fiscal year 2003 decreased by $28.9 million to $673.8 million, from $702.7 million in fiscal year 2002. The revenue level in 2003 remained high due to the continued high level of activity in West Africa on the major Conventional and SURF projects (OGGS, Yokri, Bonga and Sanha Bomboco). Revenue for fiscal year 2005 is expected to be higher than in 2004 mainly due to our $550 million share in the Greater Plutonio project awarded in February 2004 for execution during 2004 to 2007, and full year operations on the Amenam II, Benguela Belize and Erha projects.

Operating Expense

AFMED’s operating expense in fiscal year 2004 was $477.8 million, down by $362.0 million compared to $839.8 million in fiscal year 2003. The reduction relates to completion of Legacy Projects and lower activity levels in the AFMED region in fiscal year 2004. Operating expense in fiscal year 2003 was exceptionally high, at $839.8 million compared to operating expenses in fiscal year 2002 of $681.9 million. This reflects the high level of provisions recorded on loss-making Legacy Projects, particularly on the Sanha Bomboco project, where difficulties were encountered in completing the hook-up phase. Additionally, the operating expenses of Sonamet and Sonastolt were included for the first time. These expenses were $7.8 million in the aggregate for the third and fourth quarters of fiscal year 2004. The level of operating expense for 2005 is expected to increase due to increased activity levels in the AFMED region, mainly related to the Greater Plutonio project.

Net Income (Loss) Before Tax

In fiscal year 2004, AFMED reported a net profit before tax of $27.0 million as compared to a loss of $285.2 million in fiscal year 2003. This is mainly due to favorable settlements achieved in the fourth quarter on the Legacy Projects Bonga and Yokri. The net result before tax for fiscal year 2002, was a loss of $36.6 million. This degradation in trading performance in 2003 mainly related to $65.1 million of fixed asset impairments together with negative revisions totaling $190.3 million, on four large loss-making Legacy Projects, namely OGGS, Sanha Bomboco, Bonga and Burullus. We believe that AFMED’s prospects for fiscal year 2005 are better than in fiscal year 2004, as all remaining legacy contracts have been operationally completed.

Northern Europe and Canada Region (NEC)

Net Operating Revenue

NEC’s net operating revenue decreased by $45.9 million to $341.7 million in fiscal year 2004 from $387.6 million in fiscal year 2003. The reduction was mainly in SURF activity in the Norwegian sector of the North Sea, following completion of the Vigdis Extension and Skirne Byggve projects in 2003, which were not replaced by contracts of the same magnitude. SURF activity in the U.K. sector increased mainly due to the Arthur project for Mobil North Sea Ltd. and the Clair and Endeavour projects for BP. IMR-related revenues in the Norwegian sector were higher in 2004 than 2003 due to increased activity on the Shell Draugen project. Net operating revenue increased to $387.6 million in fiscal year 2003 from $335.6 million in fiscal year 2002. The increased revenues in fiscal year 2003 were mainly from the additional SURF activity in the Norwegian sector for the Vigdis Extension and the Skirne Byggve projects. In 2002, there were no significant Conventional lump sum or pipelay projects in this region.

We expect NEC’s overall revenue in fiscal year 2005 to be higher than in fiscal year 2004 due to the start-up of the first offshore phase of the Langeled project. This is a two year Trunkline project awarded in the first half of fiscal year 2004 and involves laying a 900 km trunkline from the Norwegian sector in the North Sea to the east coast of southern United Kingdom.

We expect IMR-related activity to be lower than in fiscal year 2004, mainly due to completion of the frame agreement with Shell Norway on the Draugen project.

Operating Expense

Operating expense in fiscal year 2004 decreased by $55.8 million to $287.2 million compared to $343.0 million in fiscal year 2003, reflecting the reduced level of activity in the NEC region. NEC’s operating expense in fiscal year 2003 was $343.0 million compared to operating expense in fiscal year 2002 of $307.2 million. We are expecting the level of operating expense for 2005 in the NEC region to increase proportionally with the increased activity levels, mainly related to the Langeled project.

Net Income (Loss) Before Tax

In fiscal year 2004, NEC reported net profit before tax of $46.1 million as compared to $23.1 million in fiscal year 2003. This increase is mainly due to better than expected ship utilization on the Draugen project; the release of costs accrued in fiscal year 2003 for rectifying technical problems on the Skirne Byggve project due to lower than expected expenses; settlement of claims from 2002 on the Conoco CMS3 project; and high levels of activity on a new joint venture with Subsea 7 (“EPIC JV”). On the Arthur project for Mobil North Sea Ltd., problems were experienced during trenching due to difficult seabed soil conditions, weather and umbilical damage, which resulted in losses of $10.0 million. The net result before tax for fiscal year 2003 was a profit of $23.1 million compared with $10.8 million in fiscal year 2002. The 2003 result included a provision for losses on the Skirne Byggve project. We anticipate that the net income before tax for fiscal year 2005 of the NEC region will remain high, but will be more comparable with the level attained in fiscal year 2003 than in fiscal year 2004.

North America and Mexico Region (NAMEX)

Net Operating Revenue

NAMEX’s net operating revenue in fiscal year 2004 decreased by $30.0 million to $170.6 million compared to $200.6 million in fiscal year 2003. The major portion of the reduction was due to Conventional projects, which were not replaced by new projects of similar magnitude following the completion of the Duke Hubline project in 2003. The revenues in fiscal year 2004 from the Angostura project in Trinidad and Tobago were less than originally expected due to delays caused by mechanical problems with the DLB 801 . The level of SURF activity was higher than the previous year due to the Seaway Kestrel being transferred to the NAMEX region. IMR

activity levels in fiscal year 2004 were at the same levels as in fiscal year 2003 due to repair work throughout the fourth quarter in fiscal year 2004 as a result of damage to offshore installations from Hurricane Ivan in the Gulf of Mexico. Net operating revenue in fiscal year 2003 increased to $200.6 million from $190.5 million in fiscal year 2002. The increase reflected activity from the Duke Hubline project in the Conventional segment, offset by lower SURF activity due to lack of a dedicated ship in the NAMEX region. We expect NAMEX’s net operating revenue for fiscal year 2005 to be higher than for fiscal year 2004, because of the high level of activity for the DLB 801 on Conventional projects in Trinidad and Tobago despite a planned dry-docking during the year.

Operating Expense

Operating expense in fiscal year 2004 was $213.7 million, a marginal increase compared to $208.9 million in fiscal year 2003. The costs reflected a mechanical problem with the DLB 801 on the Angostura project. The resulting delays in the project resulted in an amount of $5.1 million being recorded for liquidated damages. It also meant that work was performed under more difficult weather conditions in Trinidad, which resulted in additional costs being incurred. NAMEX’s operating expense in fiscal year 2003 was $208.9 million compared to operating expenses in fiscal year 2002 of $193.0 million. The activity level for 2005 is expected to be higher, mainly related to the Conventional business segment. As the projected loss at completion on the Angostura and NGC-Bud projects has been provided for in fiscal year 2004, operating expense is expected to be lower in fiscal year 2005.

Net (Loss) Income Before Tax

Net loss before tax for NAMEX was $49.3 million in fiscal year 2004, compared to a net loss of $32.3 million in fiscal year 2003. The majority of this loss was incurred in the Conventional business segment and is attributable to the Angostura and NGC-Bud projects in Trinidad and Tobago caused by equipment failure on the DLB 801 barge. In addition, a significant underutilization of some of the major regional assets was caused by the delay on the Angostura project. The net loss before tax for fiscal year 2003 of $32.3 million, included $12.4 million of tangible fixed assets impairment charges and losses in the Conventional business segment, specifically on the Duke Hubline project where unexpected weather conditions, poor subcontractor performance and changes in site conditions resulted in disputes over the level of charges invoiced to the customer on a cost-plus basis. This net loss for fiscal year 2003 compared to a net loss of $116.0 million in fiscal year 2002, which included a goodwill write-off of $103.0 million. We expect NAMEX’s net results for fiscal year 2005 to be better than fiscal year 2004, which includes charges of $36.3 million associated with the loss-making contracts in Trinidad.

South America Region (SAM)

Net Operating Revenue

SAM’s net operating revenue decreased marginally in fiscal year 2004 by $1.0 million to $55.0 million compared to $56.0 million in fiscal year 2003. This decrease in revenue is mainly related to the sale of the ROV drill support business in February 2004. The ship utilization on the two long-term charter contracts operating in the region continued to be high during 2004. Net operating revenue in fiscal year 2003 increased to $56.0 million from $52.0 million in fiscal year 2002 due to very high ship utilization under the long-term contracts operating in the SAM region, as well as good performance on the other regional assets, including the contracts for ROV drill support and survey.

We expect net operating revenue for 2005 to be lower than fiscal year 2004 because both Seaway Condor and Seaway Harrier will be taken off the long-term contract due to scheduled dry-docking. The long-term contract for the hire of the Seaway Harrier by Petrobras is due for renewal in 2005.

Operating Expense

SAM’s operating expense in fiscal year 2004 was $41.0 million, an increase of $6.4 million as compared to $34.6 million in fiscal year 2003. This increase is mainly related to thruster issues experienced on both the

Seaway Condor and Seaway Harrier in the fourth quarter of fiscal year 2004 and recorded employee-related provisions of $2.3 million in respect of claims from former employees and social security payments. Operating expense in fiscal year 2003 was $34.6 million compared to operating expense in fiscal year 2002 of $40.5 million. We are expecting the level of operating expense to be lower in fiscal year 2005 in line with the lower level of activity as described above.

Net Income (Loss) Before Tax

Net profit before tax for SAM was $11.3 million in fiscal year 2004, a decrease of $6.9 million from fiscal year 2003. This decrease is principally attributable to the $6.4 million increase in operating expense referred to above. The profit for fiscal year 2003 of $18.2 million increased by $12.7 million from fiscal year 2002 primarily due to exceptionally favorable operating conditions. Net income in SAM for fiscal year 2005 is expected to be lower than in fiscal year 2004 due to both the Seaway Condor and Seaway Harrier being taken off the long-term contract due to scheduled dry-docking, including the upgrading of the Seaway Harrier .

Asia and the Middle East Region (AME)

Net Operating Revenue

AME’s net operating revenue increased in fiscal year 2004 by $5.1 million to $31.9 million from $26.8 million in fiscal year 2003, due to increased levels of business. The majority of the revenue in fiscal year 2004 continued to be derived from shallow water IMR, Conventional and survey projects in Indonesia, where the activity levels were still lower than expected. Net operating revenue in fiscal year 2003 increased marginally by $1.1 million to $26.8 million from $25.7 million in fiscal year 2002 due to lower than expected activity levels in fiscal year 2002. We expect revenues in AME for fiscal year 2005 to be higher than those experienced in the last three fiscal years due to the award of the Casino project, and the relocation of the Seaway Hawk to the AME region. In addition, we have continued to expand and strengthen its AME region operations commercially in order to take advantage of the opportunities offered by the growing SURF market.

Operating Expense

AME’s operating expense in fiscal year 2004 was $26.4 million, marginally reduced by $0.4 million compared to $26.8 million in fiscal year 2003. Operating expense in fiscal year 2003 was $26.8 million compared to operating expense in fiscal year 2002 of $23.6 million. The operating expense for 2005 is expected to increase due to the execution of the Casino project.

Net Income (Loss) Before Tax

AME’s net result before tax for fiscal year 2004 was a profit of $2.5 million, compared to a net loss before tax of $6.5 million in the previous year. This is mainly attributable to a higher volume of overall activity in Indonesia compared to 2003, which has resulted in high utilization of certain regional assets, and also strong margins on IMR projects. The deterioration in the net loss to $6.5 million in fiscal year 2003 from a net loss of $3.4 million in 2002 was mainly due to the low volume of activity in Indonesia which led to an underutilization of certain assets as well as competitive pricing pressures, which depressed project margins. We recognize that the entrance into the SURF market in this region will not be simple and therefore expect that the net results in fiscal year 2005 will remain close to break-even.

Corporate

Net Operating Revenue

Net operating revenue was significantly reduced in fiscal year 2004 by $30.8 million to $106.7 million from $137.5 million in fiscal year 2003. This was due to the sale of Serimer DASA in the second quarter of 2004 and Paragon Litwin in the third quarter of 2004.

Net operating revenue increased marginally in fiscal year 2003 to $137.5 million from $131.0 million in 2002. This increase was attributable to higher sales achieved by Serimer DASA on offshore welding work for customers other than us and stable revenue levels in the Paragon Companies. As our interest in Paragon Engineering Services, Inc. was sold during the first quarter of 2005 we expect Corporate’s net operating revenue prospects for fiscal year 2005 to decrease since it will only reflect the revenues related to Paragon Engineering Services, Inc. up to the date of its sale in January 2005.

Operating Expense

The Corporate segment’s operating expense in fiscal year 2004 was $82.9 million, down by $30.6 million compared to $113.5 million in fiscal year 2003. The decrease reflected the sale of Serimer DASA in the second quarter and Paragon Litwin in the third quarter of 2004. Operating expense in fiscal year 2003 was $113.5 million compared to operating expenses in fiscal year 2002 of $128.2 million. The operating expense for 2005 is expected to decrease due to the non-inclusion of Serimer DASA and the Paragon Companies.

Net (Loss) Income Before Tax

Corporate reported a net loss before tax for fiscal year 2004 of $23.3 million, compared to a net loss before tax of $136.0 million in fiscal year 2003. The main reasons for the loss in 2004 were asset write-offs of $4.2 million related to trenching ploughs, asset underutilization mainly related to the LB 200 which was not utilized in 2004, external consultancy fees of $19.0 million in relation to our financial restructuring (excluding capitalized debt issuance costs relating to the $350 million revolving credit facility) and a $4.0 million provision relating to the KSRP. Corporate reported a net loss before tax for fiscal year 2003 of $136.0 million compared with a net loss before tax of $4.1 million in fiscal year 2002. The increased loss in fiscal year 2003 was related to $99.0 million in impairment charges on some of the major ships, (notably the Seaway Kestrel and the Seaway Explorer) and mobile assets; the ship-mounted radial friction welding system; $10.0 million in our share of losses from the NKT Flexibles joint venture investment; $4.5 million in restructuring charges; external fees regarding financial restructuring; and asset under-recovery. We expect net income before tax for Corporate for fiscal year 2005 to be positive, mainly related to high utilization of the Seaway Eagle and the Seaway Falcon , which are dedicated as Group assets.

Consolidated Results

Net Operating Revenue

Net operating revenue decreased to $1,241.9 million in fiscal year 2004 from $1,482.3 million in fiscal year 2003, as we executed the reduced backlog brought forward from the previous year, and disposed of Serimer DASA and Paragon Litwin. Net operating revenue in fiscal year 2003 increased slightly to $1,482.3 million from $1,437.5 million in fiscal year 2002. This reflected major projects in NEC and AFMED. Revenue in fiscal year 2005 is expected to be higher than in fiscal year 2004, reflecting the increased level of backlog as at November 30, 2004 and the inclusion of a full year’s revenue from the Sonamet and Sonastolt entities, which will be offset by the exclusion of revenue of Serimer DASA and the Paragon Companies.

Equity in Net Income of Non-consolidated Joint Ventures

Equity in net income of non-consolidated joint ventures in fiscal years 2004, 2003 and 2002 was as follows:


Period ended November 30, (in millions)	2004		2003		2002
	$		$		$
NKT Flexibles I/S	(5.0	)	(10.0	)	(14.0	)
Mar Profundo Girassol (“MPG”)	(3.1	)	(0.8	)	(1.2	)
Sonamet/Sonastolt	7.0	^(a)	4.9		7.1
Seaway Heavy Lifting JV	5.9		3.2		2.7
Stolt/Subsea 7	3.5		4.0		10.3
Kingfisher D.A.	0.6		(0.9	)	0.4
Dalia FPSO	(1.7	)	—		—
EPIC	7.8		—		—

Total	15.0		0.4		5.3

(a)	Excludes Sonamet and Sonastolt data for the 6 months ended November 30, 2004.

This increase in 2004 to $15.0 million in fiscal year 2004 from $0.4 million in 2003 was largely due to the successful first year of operation of the new EPIC JV with Subsea 7 on the Ekofisk field, which contributed $7.8 million. There was also an improved contribution of $5.9 million from SHL, where the heavy lift barge Stanislav Yudin had an extended period of high utilization in the Arabian Gulf. The Subsea 7 joint venture, whose contract covers IMR work on various fields in the Norwegian sector of the North Sea, continued to deliver a high level of performance in fiscal year 2004, although reduced by 12.5% compared to 2003. In addition, the results for fiscal years 2003 and 2002 were negatively impacted by our share of losses of $10.0 million and $14.0 million from the investment in NKT Flexibles. These included losses of $6.6 million and $8.1 million in 2003 and 2002 respectively, in respect of our share of tangible fixed asset impairments. See “—Results of Operations—Consolidated Results—Impairments of Tangible Fixed Assets”.

The increases in 2004 were offset by the exclusion of the results of Sonamet and Sonastolt in the third and fourth quarters of fiscal year 2004—the results of these two Angolan ventures for that period are included in our Consolidated Statements of Operations from May 31, 2004 onwards. There were continuing losses on the MPG joint venture, resulting from a reassessment of MPG’s exposure under the repair claim from its customer, and the Dalia FPSO joint venture has yet to report a profit on the FPSO topsides construction contract.

Selling, General and Administrative (“SG&A”) Expenses

SG&A expenses in fiscal year 2004 were $118.4 million, compared to $102.5 million and $89.7 million in fiscal years 2003 and 2002, respectively. The increase in fiscal year 2004 was mainly due to external advisors’ fees of $19.0 million incurred in connection with the completion of the financial restructuring program as well as $4.0 million relating to the KSRP.

As a condition of the new $350 million revolving credit facility, an agreement that was finalized in fiscal year 2004, the banks required us to put in place a KSRP in order to secure the services of certain senior executives through to the first quarter of fiscal year 2007. The KSRP provides for deferred compensation as a combination of cash and performance-based share options, linked to the attainment of a number of strategic and financial objectives for each of the fiscal years 2004, 2005 and 2006. We have accrued in 2004 for the proportion of compensation expense relating to the service period completed to date, taking into account the probability of the performance conditions being met over the period of the plan. The total cost of the KSRP recorded in 2004 was $4.0 million.

The increase in fiscal year 2003 over fiscal year 2002 was mainly due to external advisors’ fees incurred in connection with the financial restructuring program. As discussed in Note 2 to the Consolidated Financial

Statements, the reported amounts for fiscal year 2002 have been reclassified for comparability to reflect the reorganization of our management structure. We reclassified health, safety and environment and quality costs because they are incurred in relation to project work.

Impairment of Tangible Fixed Assets

In accordance with SFAS No. 144, long-lived assets identified as held for use are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. We measure assets held for sale at the lower of cost and fair value less cost to sell. In fiscal year 2004 we recorded impairment charges totaling $9.4 million in respect of our tangible fixed assets, as set forth below:

Ships and Other Offshore Equipment—$4.2 million

We recorded an impairment charge of $1.9 million in the second quarter of fiscal year 2004 in respect of the Seaway Explorer on the basis of the negotiations for its sale, which was completed in the third quarter of fiscal year 2004. The carrying values of a number of other assets were reassessed and impairments recorded in the second and third quarters of fiscal year 2004, when market valuations were updated. These included the Saturation Dive System on the Seaway Condor , the Seaway Legend , the Seaway Kestrel , and the Deep MATIS ^{^™} system.

Underutilized Mobile Equipment—$5.2 million

During the preparation of the 2005 annual operating budget and three-year plan in October 2004, our senior management reassessed the level of expected future utilization of all its long-lived assets in light of our business strategies. Consequently, we identified a number of assets that are expected to be underutilized. The major items included an ROV, three trenchers and ploughs. We estimated that future cash flows attributable to these assets were less than their carrying values and recorded an impairment charge on the basis of fair value calculations performed by us using discounted cash flows.

In fiscal year 2003, we recognized aggregate impairment charges of $176.6 million. As discussed in Note 10 to the Consolidated Financial Statements, this was made up of: Ships offered for sale ($44.2 million); LB 200 pipelay barge ($55.7 million); radial friction welding system ($42.7 million); other ships and offshore equipment ($28.9 million); and the Lobito Yard assets ($5.1 million). The fiscal year 2002 charge of $4.0 million for impairment of fixed assets was made up of adjustments to the carrying value of several small fixed assets.

Impairment of Goodwill and Other Intangible Assets

We did not record any charges for impairment of goodwill or other intangible assets in fiscal year 2004 or 2003. Goodwill as at November 30, 2004 amounted to $5.3 million in respect of the acquisition of Paragon Engineering Services, Inc. in fiscal year 2001. Our interest in the subsidiary was sold for a gain of $2.1 million on January 19, 2005.

In fiscal year 2002, the continuing poor returns obtained on certain investments made in 1998 and 1999 led us to perform an impairment review of all goodwill recognized on past acquisitions. As a result, we recorded impairment charges totaling $106.4 million against goodwill, of which $103.0 million related to the entire remaining goodwill on the 1998 acquisition of Ceanic. The remainder of the charge eliminated the outstanding goodwill of $1.8 million on the acquisition of Danco A/S, which holds our investment in NKT Flexibles, and of $1.6 million in respect of our Indonesian subsidiary, PT Komaritim.

Restructuring Charges

We recorded restructuring charges of $2.7 million in fiscal year 2004, although no new initiatives were undertaken. We increased the existing accrual for future rental costs on the office space vacated by Paragon

Litwin by $2.6 million in the AFMED region to reflect the weakness of the local real estate market for subletting these premises (before the end of 2006). Other revisions to estimates were recorded in respect of higher than anticipated professional fees, and lower than expected personnel and redundancy costs.

In fiscal year 2003, restructuring charges of $16.2 million were recorded resulting from the implementation of the new management team’s plan for financial recovery, which included the restructuring of our cost and asset base. The charges included personnel and redundancy costs of $13.2 million due to the reduced staffing levels and real estate costs of $2.7 million, primarily reflecting accrued rental fees in the office space vacated by Paragon Litwin.

The table below illustrates the development of restructuring costs during 2004:


For the fiscal year ended November 30, 2004 (in millions)	Opening balance	Expensed in the year	Released to income		Paid in the year		Other ^(a)	Closing Balance
	$	$	$		$		$	$
Real estate costs	2.7	2.6	—		(0.9	)	0.3	4.7
Personnel and redundancy costs	12.6	0.6	(0.7	)	(12.9	)	1.0	0.6
Professional fees	0.3	0.3	(0.1	)	(0.5	)	—	—

Total	15.6	3.5	(0.8	)	(14.3	)	1.3	5.3

(a)	Includes the effect of exchange rate changes.

There were no restructuring charges in fiscal year 2002.

Gain (Loss) on Sale of Fixed Assets

In fiscal year 2004, the gain of $4.7 million includes $2.0 million from the disposal of the ROV business and $1.1 million from the disposal of ships (the Annette , the Seaway Rover , the Seaway Invincible, the Seaway Pioneer, and the Seaway Explorer) . In fiscal year 2003, the loss of $0.3 million resulted from the disposal of surplus equipment in the AME region, and the gain of $8.0 million in fiscal year 2002 represented the gain from the sale of the assets of Big Inch Marine Systems, Inc.

Gain on Sale of Subsidiaries

In fiscal year 2004 the total gain of $25.2 million consists of a gain of $26.1 million from the disposal of Serimer DASA, partially offset by a loss of $0.9 million from the disposal of Paragon Litwin and Paragon Italia S.r.L.

Other Operating Income (Loss), Net

In fiscal year 2004 we recorded other operating gains of $1.4 million compared to other operating losses of $1.1 million in fiscal year 2003 and other operating income of $0.1 million in fiscal year 2002. No significant individual transactions are included in these results.

Net Interest Expense

In fiscal year 2004, net interest expense decreased to $15.9 million from $24.8 million in fiscal year 2003. This reduction resulted from scheduled repayments and restructuring of our then existing credit facilities and the conversion by SNSA of our $50 million subordinated note into 22.7 million Common Shares on 20 April 2004. Also included was a charge of $1.8 million in respect of the retirement in November 2004 of the previous facility. The amount results from the write-off of the unamortized portion of the fees and costs of the setting up of the previous facility. In fiscal year 2003, net interest expense increased to $24.8 million from $18.2 million in

fiscal year 2002. This resulted from increased borrowings from SNSA under the $50 million subordinated note, and from the decision to fully draw down our then existing credit facility agreements in August 2003 to assure liquidity during the restructuring process.

Foreign Currency Exchange Gains (Losses)

During fiscal year 2004 we recorded a foreign exchange related gain of $6.2 million compared to a $8.9 million loss in fiscal year 2003. This gain resulted primarily from cash balances held in currencies other than the U.S. dollar.

Income Tax (Provision) Benefit

We recorded a net tax charge of $9.2 million in fiscal year 2004, as compared to a net tax benefit of $0.6 million in fiscal year 2003. The tax charge in fiscal year 2004 comprised a charge to current tax of $15.5 million, a charge for revenue-based withholding taxes of $7.5 million, and a deferred tax benefit of $13.8 million. The tax benefit in fiscal year 2003 comprised a net release to current tax of $0.03 million, a charge for revenue-based withholding taxes of $6.6 million, and a deferred tax benefit of $7.2 million. We recorded a net tax charge of $8.2 million in fiscal year 2002.

We have recognized deferred tax assets for the tax effects of temporary differences and net operating losses carried forward (“NOLs”) in Indonesia, Norway and the United Kingdom, totaling $16.7 million. Due to continued depression in our NAMEX region, we have not recognized any deferred tax benefit for the NOLs arising in the United States. While we have potential future tax deductions and NOLs in several other countries, we have recorded valuation allowances against the corresponding deferred tax assets in those instances where it is unlikely that tax deductions will materialize. Across our subsidiaries, we have NOLs of $215 million, none of which will expire within 5 years.

During fiscal year 2004, we settled some disputes in Norway, resulting in a small credit. We also reviewed provisions for unresolved items in the Netherlands, Indonesia and various countries within the AFMED region, which resulted in us booking an additional net current tax expense of $9.9 million. These resulted from computations of liabilities in the normal course of negotiations with the authorities and consultation with advisers. Where there are ongoing inquiries, management considers that we have defenses to the issues being raised and considers that the amount provided as at November 30, 2004, reflects our best estimate of amounts that will ultimately be due for fiscal years up to and including 2004. However, the assessments issued to date, which cover fiscal periods up to November 30, 2001, are in aggregate $34.4 million higher than the taxes provided as at November 30, 2004, not including any interest and penalties that may be payable.

Under United Kingdom Tonnage Tax legislation, a portion of tax depreciation previously claimed by us may be subject to tax in the event that a significant number of vessels are sold without being replaced. This contingent liability reduces progressively to nil over the seven years following entry into the Tonnage Tax regime. Management has made no provision for the contingent liability relating to ships because it is not probable that we will sell ships under circumstances that will make it subject to Tonnage Tax legislation. The unrecorded contingent liability in respect of all ships as at November 30, 2004 was $27.5 million.

Depreciation and Amortization

Depreciation and amortization in fiscal year 2004 amounted to $65.6 million compared to $93.5 million and $92.1 million in fiscal years 2003 and 2002, respectively. The main reason for the reduction in fiscal year 2004 is the reduction of the fixed asset base due to numerous disposals of fixed assets and the impairment charges recorded in the fourth quarter of fiscal year 2003 and during fiscal year 2004.

Net Income (Loss) Before Tax

The net income (loss) before tax was affected by a number of significant credits (charges), which are summarized in the following table. These, together with the tax charge, had the most significant role in the

increase in net income to $5.1 million in 2004 as compared to net losses of $418.1 million and $151.9 million in 2003 and 2002, respectively.


Significant Credits (Charges) (in millions)	2004		2003		2002
	$		$		$
Revisions of estimates on major projects	12.5		(216.0	)	(58.8	)
Charge for impairment of company-owned tangible fixed assets	(9.4	)	(176.5	)	(4.0	)
Share of impairment charge of tangible fixed assets in equity joint ventures	—		(9.1	)	(8.1	)
Charge for impairment of goodwill and other intangible assets	—		—		(106.4	)
Restructuring charge	(2.7	)	(16.2	)	—
Financial restructuring—external advisors	(19.0	)	(6.2	)	—
Increase in provision for patent settlement (see “—Legal, Regulatory and Insurance Matters” below)	—		(7.8	)	—
Gain on sale of subsidiaries	25.2		—		—
Gain (Loss) on sale of fixed assets	4.7		(0.3	)	8.0
Key Staff Retention Plan charge	(4.0	)	—		—

Total significant credits (charges)	7.3		(432.1	)	(169.3	)

Liquidity and Capital Resources

Cash Requirements, Contractual Obligations and Commercial Commitments

Our primary cash uses are to fund working capital, acquisitions of fixed assets, operating expenditures and dry-docking costs.

As at November 30, 2004, we had available borrowing facilities of $175 million, of which $60 million was utilized. Together with cash balances of $135.0 million the net available liquidity was $250 million. This compared to available liquidity as at November 30, 2003 of $81.9 million. This increase was due to strong cash flows from contracts (including advance payments of $148 million), the issuance of new shares, the disposal of existing assets and the availability of new debt facilities.

Contractual Obligations

The following table sets forth our contractual obligations and other commercial commitments as at November 30, 2004:


Contractual Obligations (in millions)	Total	Less than 1 year	1–3 years	4–5 years	After 5 years
	$	$	$	$	$
Long-term debt ^(a)	60.0	—	—	60.0	—
Operating lease obligations	96.4	30.0	43.9	13.6	8.9
Purchase obligations	179.8	140.2	39.6	—	—
Other ^(b)	259.0	151.5	95.1	12.4	—

(a)	Represents principal amounts, but not interest, excluding the $9.7 million loan from Sonangol to Sonamet. See Note 16 to the Consolidated Financial Statements. For a description of our long-term debt, please refer to “—Description of Indebtedness” below.

(b)	Other includes performance bonds, bid bonds, advance payment bonds, guarantees or standby letters of credit in respect of our performance obligations. For further information regarding bank guarantees, see “—Off-Balance Sheet Arrangements” below.

Cash Management Constraints

Our cash operations are managed under central treasury department control, and cash surpluses and requirements are identified using consolidated cash flow forecasts. We do not always have the ability to freely transfer funds across international borders. For example, certain subsidiary companies in France which show a negative net asset position are unable to release funds to central treasury without approval from the subsidiary’s board of directors. In addition, approval from the Central Bank of Brazil is required to obtain remittances from Brazil and access to the $43.5 million of cash held by Sonamet and Sonastolt may be limited because it would require agreement between the minority shareholder and us.

The main uncertainties with respect to our primary sources of funds are as follows: the ability to obtain borrowings from financial institutions at commercially acceptable terms; being able to issue share capital at terms acceptable to us; the ability to agree, in a timely fashion, with customers the amounts due as claims and variation orders; the availability of cash flows from joint ventures; and the timing of asset or business disposals through its divestment program. In addition, due to the uncertainties associated with the timings of cash flows from project contracts, and the uncertainties referred to earlier, it is difficult to accurately forecast the timing of inflows and outflows of cash.

Future Compliance with Debt Covenants

As described in Note 16 to the Consolidated Financial Statements, our credit facilities contain various financial covenants, including but not limited to, a minimum level of tangible net worth, a maximum level of net debt to EBITDA, a maximum level of total financial debt to tangible net worth and a minimum level of cash and cash equivalents. We must meet the requirements of the financial covenants on a consolidated basis in quarterly intervals ending February 28, May 31, August 31, and November 30, of each year. Given the improved performance of the business and the more favorable financial covenants in the new credit facilities, we believe, based on our latest forecasts for fiscal year 2005, that we will be able to comply with all financial covenants during fiscal year 2005, even if there is a significant deterioration in market conditions or material cost overrun on contracts.

Sources of Cash

Our principal sources of funds since the beginning of fiscal year 2004 have been cash from operations, borrowings from commercial banks, proceeds of sales of fixed assets and subsidiaries and the issuance of share capital.

Therefore, our only readily available funds for ongoing operations are: (i) the available $175 million under the $350 million revolving credit facility, of which $60 million was drawn as at November 30, 2004; and (ii) our cash on hand and cash flows from operations going forward. As at November 30, 2004, we had $135.0 million of unrestricted cash on hand.

We believe that our ability to obtain funding from the sources described above will continue to provide the cash flows necessary to satisfy our working capital requirements and capital expenditure requirements, as well as meet our debt repayments and other financial commitments for at least the next 12 months. We also have the ability to pledge additional assets in order to raise additional debt.


Summary Cash Flows (in millions)	2004		2003		2002
	$		$		$
Cash and cash equivalents at the beginning of the year	81.9		11.7		11.7
Net cash provided by (used in) operating activities	152.1		(27.5	)	84.7
Net cash provided by (used in) investing activities	66.8		(12.7	)	(76.4	)
Net cash (used in) provided by financing activities	(172.5	)	109.4		(8.4	)
Effect of exchange rate changes on cash	6.7		1.0		0.1

Cash and cash equivalents at the end of the year	135.0		81.9		11.7

Cash Flows Provided by (Used in) Operating Activities

Cash flow from operations is derived principally from the collection of receivables due from customers under project contracts. The timing of invoice preparation for long-term contracts is typically based on progress towards the completion of work, either defined as agreed project “milestones” or an otherwise agreed staged payment schedule. Cash flows do not always coincide with the recognition of revenues, as customers are generally required to make advance payments at project commencement. It is our intention, when negotiating a contract, to arrange for cash to be received from the customer in advance of the requirement to pay suppliers, thus ensuring a neutral impact on liquidity. As at November 30, 2004 we had received $148 million in advance payments from its customers.

Net cash provided by operating activities during fiscal year 2004 was $152.1 million compared to net cash used in operating activities of $27.5 million during fiscal year 2003. This resulted from cash provided by operations of $37.9 million, a reduction in working capital of $94.5 million and dividends of $19.7 million received from non-consolidated joint ventures. Average accounts receivable decreased from 99 days to 89 days as at November 30, 2004. Average accounts payable days decreased to 92 days as at November 30, 2004 from 102 days as at November 30, 2003. The other year-to-year fluctuations in cash flows from operating activities are due to fluctuations in net operating income as discussed under “Business Segment Results” above.

Net cash used in operating activities during fiscal year 2003 was $27.5 million compared to net cash provided by operating activities of $84.7 million during fiscal year 2002. This resulted from cash used in operations of $135.1 million, only partially offset by a reduction in working capital of $93.5 million and dividends of $14.1 million received from non-consolidated joint ventures. Average accounts receivable decreased to 99 days as at November 30, 2003 from 102 days as at November 30, 2002. Average accounts payable days decreased to 102 as at November 30, 2003 from 120 as at November 30, 2002. The other year-to-year fluctuations in cash flows from operating activities are due to fluctuations in net operating income as discussed under “—Results of Operations—Business Segment Results” above.

Cash Flows Provided by (Used in) Investing Activities and Capital Expenditures

Net cash provided by investing activities in fiscal year 2004 was $66.8 million compared to net cash used in investing activities of $12.7 million in fiscal year 2003. This primarily comprises: net cash inflows from asset sales relating to the disposals of Serimer DASA, the ROV business, ships, the Lobito Yard assets and other minor items totaling $75.0 million; $32.8 million added by the consolidation of Sonamet and Sonastolt following the adoption of FIN 46R; less the purchase of fixed assets of $34.2 million including the capital expenditure discussed below and other investments of $6.8 million.

In addition to projecting specific capital expenditure outflows, which are typically included in the contract price, we, in the normal course of our business, make routine capital expenditures. The table below sets forth information with respect to our capital expenditures for fixed assets in each of the last three fiscal years. The ongoing capital expenditures will be funded with cash from operations.


Category of Capital Investment (in millions)	2004	2003	2002
	$	$	$
Equipment and asset development	4.3	8.1	28.9
Capacity upgrades to ships and other equipment	24.0	12.3	24.1
Other	5.9	1.5	1.6

Total capital investment	34.2	21.9	54.6

The above investments were made in the context of our ongoing capital program, and are based on the requirement to maintain a high standard of efficiency and reliability of the offshore asset base.

The four largest capital expenditure projects during fiscal year 2004 are set out in the table below:


Asset (in millions)	Description of Capital Expenditure Project	$
LB 200	Upgrade for Langeled project		11.8
DLB 801	New stinger, upgrade of pipelay system and tensioner		5.6
Cargo barge	Purchase of new cargo barge to replace scrapped cargo barge		3.4
Sonamet/Sonastolt	New crane in Lobito yard, Angola		2.7

Total		$	23.5

Though cash restrictions have been less of an issue during fiscal year 2004 compared to fiscal year 2003, the level of the cash capital expenditure has been low in relation to the capital budget for the year of $50.8 million. This is due to the complexity of the design and engineering components of projects such as: the upgrade of the LB200, DLB801 and the Seaway Polaris J-lay tower. We expect capital expenditures in fiscal year 2005 to amount to approximately $100 million, of which $75.8 million was committed as at February 28, 2005.

Net cash used in investing activities in fiscal year 2003 was $12.7 million compared to net cash used in investing activities of $76.4 million in fiscal year 2002. This amount mainly comprised net cash inflows of $31.9 million in respect of repayments from and advances to joint ventures, other investments and other non-current financial assets partially offset by the payment of $12.5 million for the final settlement of the NKT Flexibles share price guarantee, a further investment in the Sonamet and NKT Flexibles joint ventures of $14.2 million, asset sales proceeds of $4.0 million and the purchase of fixed assets of $21.9 million.

Net cash used in investing activities in fiscal year 2002 mainly comprised the payment of $58.9 million to Vinci in respect of the settlement of our conditional obligation to pay additional consideration related to the difference between the price Vinci received for our shares it sold and the guaranteed minimum share price of $18.50 per Common Share agreed by us in connection with the acquisition of ETPM from Vinci, and the payment of $1.7 million for the settlement of a similar liability related to the acquisition of our interest in NKT Flexibles. This was partially offset by $23.5 million from the sale of the assets, including those of Big Inch Marine Systems, Inc. Investments made in the purchase of fixed assets were $54.6 million, and $15.2 million was received in respect of investments in non-consolidated joint ventures.

Cash Flows (Used in) Provided by Financing Activities

In 2004, we restructured our capital base using the net proceeds from our equity capital raising transactions and the new $350 million revolving credit facility, to refinance $385 million of existing bank debt. Additionally, the cash available from operations and the equity capital reduced the need to use cash from borrowings and other financing sources to fund operations. Net cash used in financing activities in fiscal year 2004 was $172.5 million, compared to net cash provided by financing activities in fiscal year 2003 of $109.4 million. Sources of financing totaling $224.7 million in fiscal year 2004 were $155.0 million of net proceeds from the issuance of Common Shares, a $60 million drawdown under the new $350 million revolving credit facility, and a $9.7 million loan from a minority shareholder. The funds were used to repay $390.8 million of outstanding long-term debt, $2.5 million to repay a bank overdraft, and to pay $3.9 million in dividends to a minority shareholder in an operating subsidiary.

Net cash provided by financing activities in fiscal year 2003 was $109.4 million, compared to net cash used by financing activities in fiscal year 2002 of $8.4 million. Sources of financing in fiscal year 2003 were a net increase of $149.6 million in long-term debt and the monetization of hedges with proceeds of $16.8 million. These funds were used to repay bank overdrafts of $13.8 million, to pay dividends to a minority shareholder of $2.2 million in an operating subsidiary and to repurchase treasury shares of $1.0 million. Furthermore, outstanding SNSA funding was reduced by $40.0 million. During the second half of fiscal year 2003, cash requirements increased significantly due to cost overruns on certain major projects, the continued delay in the recovery of amounts owed to us, and the delayed settlement of claims and variation orders with respect to major projects.

Consequently, while engaged in discussions with our primary creditors to amend the financial covenants in our existing credit facility agreements, we also took measures to ensure that we had sufficient liquidity to fund our operations and to provide for a potentially protracted period of negotiation with certain major customers regarding the settlement of claims and variation orders. These measures included borrowing to the maximum availability under our existing credit facility agreements and closing out positions under foreign exchange contracts. Sources of financing in fiscal year 2002 were the receipt of a $64.0 million loan from SNSA to fund settlement of share price guarantees and an increase in bank overdrafts of $10.2 million. These funds were used to repay capital lease purchase obligations totaling $23.7 million on the Seaway Polaris and the DLB 801 , and to repurchase shares from Vinci for $56.5 million.

Description of Indebtedness

The $350 Million Revolving Credit Facility

On November 8, 2004, we entered into a new $350 million multicurrency revolving credit and guarantee facility, with a consortium of banks led by DnB NOR Bank ASA, ING Bank N.V. and NIB Capital Bank N.V. as arrangers. This facility, together with existing cash balances, was used to refinance our then existing credit facilities, including a $440 million secured multi-currency revolving credit facility, a $55/45 million credit/guarantee facility, a $44 million secured guarantee facility, a $100 million secured bank guarantee facility and a $50 million unsecured bonding facility. It will be used for general corporate purposes, including the issuance of guarantees to support contract performance obligations and other operating requirements. The financing also released SNSA from all remaining financial guarantee obligations to us. In addition, a $50 million undrawn line of credit that SNSA provided to us expired as scheduled on November 28, 2004.

The facility provides for revolving loans of up to $175 million during the first three years, reducing to $150 million for the fourth year, and further reducing to $125 million for the fifth year, until November 8, 2009. The remaining capacity under the $350 million facility is available for bonding with a final maturity no later than May 8, 2011. Other mandatory reductions in the facility will occur (subject to cure provisions) if the valuations of the vessels (or a loss of a vessel) shall result in the asset coverage of the outstanding and available amounts under the facility being less than 120%. Borrowings under the facility may be made in minimum increments of $5 million subject to the satisfaction of certain customary conditions precedent. In addition, the facility provides that performance guarantees can be issued until final maturity of the facility. At final maturity, all performance guarantees must either expire on or before May 8, 2011 or be replaced or cash collateralized.

The facility is guaranteed by us and all of our material operating companies and ship-owning subsidiaries comprising in aggregate at least 90% (by external revenues and net fixed assets) of the group’s net fixed assets and external revenues.

The facility is secured by a first priority mortgage on most group vessels owned by such guarantors, as well as an assignment of earnings, insurances and requisition compensation with respect to certain vessels. The market value of the vessels pledged in support of the facility as at the close of such facility was approximately $500 million.

The fees and direct costs incurred in arranging this facility were capitalized and are being amortized to interest expense on a straight line basis over the period of the facility.

As at November 30, 2004, $60 million had been drawn under the part of the facility available for cash advances and $110.9 million of guarantees issued under the part of the facility available for guarantee issuances. The facility contains certain financial covenants in respect of a minimum level of tangible net worth, a maximum level of net debt to EBITDA, a maximum level of total financial debt to tangible net worth and a minimum level of cash and cash equivalents. We must meet the requirements of the financial covenants on a consolidated basis in quarterly intervals ending February 28, May 31, August 31 and November 30 of each year. The facility also contains negative pledges with respect to accounts receivable and cash.

Interest on the facility is payable at London InterBank Offered Rate (“LIBOR”) plus a margin which will be linked to the ratio of our debt to EBITDA (leverage ratio) and which may range from 1.0% to 2.375% per year. The margin is currently fixed at 1.0% for a period of six months and is reviewed every six months. The fee applicable for performance guarantees will be linked to the same ratio and may range from 0.5% per year to 1.1875% per year (currently fixed at 0.5% for six months).

The facility contains representations, affirmative covenants and negative covenants (in addition to the financial covenants listed above) which are customary for transactions of this nature and consistent with past practice. Such covenants specifically limit disposal of the pledged vessels, mergers or transfers, granting of encumbrances on pledged property, incurrence of other indebtedness, investments and loans, distributions to shareholders and cash and cash equivalents that are permitted to be held by non-obligors.

The facility also contains events of default which include payment defaults (subject to a three-day grace period), breach of financial covenants, breach of operational covenants, breach of other obligations, breach of representations and warranties, insolvency proceedings, insolvency events, illegality, unenforceability, conditions subsequent, curtailment of business, claims against an obligor’s assets, appropriation of an obligor’s assets, final judgments, cross-defaults to other indebtedness in excess of $5 million, change of our executive management, failure to maintain exchange listing, material adverse change, auditor’s qualification, repudiation and material litigation.

Off-Balance Sheet Arrangements

Leases and Bank Guarantees

We do not engage in off-balance sheet financing in the form of special purpose entities or similar arrangements. We engage in operating leases in the normal course of our business in respect of ship charter hire obligations, office facilities and equipment.

In the ordinary course of our business, our customers require that we provide bank guarantees (a term which collectively refers to performance bonds, bid bonds, advance payment bonds, guarantees or standby letters of credit) in support of our obligations and the obligations of our subcontractors under our project agreements. Pursuant to such bank guarantees, if we or our subcontractors fail to perform our obligations under our project agreements, subject to the terms and conditions of those agreements, our customers can draw on the bank guarantees. If we cannot provide these bank guarantees, potential customers may be unwilling to do business with us with respect to the major projects that constitute a significant portion of our business. In fiscal years 2004 and 2003, $52.6 million and $102.7 million, respectively, of bank guarantees were issued in support of our projects.

The $350 million revolving credit facility, referred to above, is available for guarantees to the extent it is not drawn as loans. In addition we have arrangements with a number of other financial institutions to issue bank guarantees on our behalf. As at November 30, 2004, the aggregate amount of guarantees issued under these facilities was $259.0 million, of which $110.9 million related to the $350 million revolving credit facility. The bonds under these facilities were issued to guarantee our project performance and that of our subsidiaries and joint ventures to third parties in the normal course of business. Other than amounts available under the $350 million revolving credit facility, we as at November 30, 2004, have no bank guarantee capacity available under these additional arrangements, which will expire together with the outstanding guarantees.

Investments in and Long-Term Funding to Non-Consolidated Joint Ventures


As at November 30, (in millions)	Geographical Location	Business segment	Ownership	2004		2003
			%	$		$
NKT Flexibles	Denmark	Corporate	49	12.0		11.0
MPG	West Africa	AFMED	50	—		0.1
Sonamet	West Africa	AFMED	55	—	^(a)	7.4
Sonastolt	West Africa	AFMED	55	—	^(a)	9.6
SHL ^(b)	Cyprus	Corporate	50	3.5		4.3
Stolt/Subsea 7	Norway	NEC	50	1.6		2.2
Kingfisher D.A.	Norway	NEC	50	3.7		3.8
Dalia FPSO	West Africa	AFMED	17.5	2.7		4.6
EPIC JV	Norway	NEC	50	0.1		—

Total				23.6		43.0

(a)

In accordance with FIN 46R, both Sonamet and Sonastolt have been accounted for as consolidated subsidiaries since May 31, 2004. Until that date they were accounted for using the equity method because our ability to control the operation of the investees is restricted by the significant participating interest held by another party.

(b)	We have 50% of the voting rights, but our profit and loss interest varies between 30% and 50%.

We offer heavy lift floating crane services through SHL. SHL charters the heavy lift barge Stanislav Yudin from a subsidiary of Lukoil Kaliningradmorneft plc, our joint venture partner in SHL. The barge operates world-wide providing heavy lift services to a range of offshore companies, including occasional projects for us.

We manufacture flexible flowlines and dynamic flexible risers through NKT Flexibles. The joint-venture has reported operating losses in each of the past three fiscal years. We made a capital contribution of $4.9 million on March 25, 2004 and in the same month the joint venture repaid $3.3 million of short-term debt to us. In order to ensure the operational solvency of the joint venture, we made additional short-term cash advances during fiscal year 2004 totaling $5.7 million, against which a full provision for doubtful recovery was recorded during the year. The provision was recorded as we did not believe it was probable of collection. No impairments to the carrying value of the joint venture’s assets were recognized in fiscal year 2004, as an impairment review in accordance with SFAS No. 144 indicated that no further charge was required in addition to those recorded in fiscal years 2003 and 2002 of $6.6 million and $8.1 million, respectively. The joint venture’s backlog has increased since November 30, 2004.

A new joint venture with Subsea 7 named EPIC was formed in fiscal year 2003 to perform IMR-related work for Statoil on the Ekofisk field in the Norwegian sector of the North Sea.

Our joint ventures in Angola with Sonangol, provide strategic access to the offshore Angolan market through the operation of the Sonamet fabrication yard at Lobito, which enables us to offer locally manufactured structures and components for offshore projects. The provision of local content is an important competitive advantage in the West African offshore market, as there are local content requirements on most projects. In addition, we provide local offshore support personnel and equipment through Sonastolt. These joint ventures are no longer off-balance sheet, as they have been consolidated from May 29, 2004, upon adoption of FIN 46R.

The Dalia Floating Production and Storage Offloading facility is a joint venture with Technip and Saipem S.A. to perform work on the Dalia field development in Block 17 offshore Angola for Total E&P Angola. The joint venture has responsibility for project management, engineering, procurement, onshore commissioning and offshore hook-up of the FPSO. Our share was initially 27.5%, but has been reduced to 17.5%. The reduction in the carrying value of the investment in the joint venture was approximately $1.5 million.

The remainder of our joint ventures have been formed either with a national oil company, or on a project-specific basis to enhance the range of services provided to the customer. We typically have interests ranging from 25% to 50% in these joint ventures.

Where joint ventures are project-specific, we will typically be obliged to contribute our proportionate share of funding requirements. In addition we may be liable for the failure of our joint venture partners to fulfil their obligations. We will normally also have an obligation to meet our proportionate share of funding needs in long-term joint ventures. However such joint venture investments would require unanimity among joint venture partners.

Legal, Regulatory and Insurance Matters

Technip

In 1996, Coflexip SA and Coflexip Stena Offshore Limited (now known as Technip S.A. and Technip Offshore Limited) (“Technip”), commenced legal proceedings in the U.K. High Court against three of our subsidiaries for infringement of a certain patent held by Technip on flexible flowline laying technology. The claim related to our use of the flexible lay system on the Seaway Falcon . On March 18, 2004, we announced that we had reached a settlement on this matter. The settlement involved: (i) a cash payment by us of an amount within our contingency reserve of $9.3 million; (ii) Technip’s grant of a license to us for the use of the allegedly infringing technology covering the North Sea area for future periods for an annual fee; (iii) the termination of arbitration proceedings in the United States with respect to an unrelated matter, with neither party making payment to the other; and (iv) a transfer to Technip of a portion of our equity interest in a project joint venture involving Technip and us. We estimated that the reduction in future profits from the transfer of this interest is approximately $6.0 million. Technip has not granted to us a license to use the allegedly infringing technology or process in any other jurisdiction. The agreed settlement was fully accrued in the Consolidated Financial Statements as at November 30, 2003.

Duke Hubline Project

In October 2003, we commenced arbitration proceedings against Algonquin Gas Transmission, in respect of unpaid invoices for work performed on the Duke Hubline project, a gas pipeline off the coast of Massachusetts in the U.S. Due to Algonquin Gas Transmission’s non-payment of invoiced amounts, we were unable to pay certain of our subcontractors employed to work on the pipeline, two of which, Bisso Marine Company and Torch Offshore Inc., filed lawsuits against us in Louisiana state court for non-payment of amounts invoiced. These same subcontractors claimed liens over the pipeline, which liens were the subject of proceedings commenced by them against us and Algonquin Gas Transmission in Massachusetts state court. The dispute with Algonquin Gas Transmission was referred to mediation in late January 2004 at which the parties reached a “settlement in principle” whereby Algonquin Gas Transmission agreed to pay us $37 million in full and final settlement of our claims we agreed to withdraw the arbitration proceedings and use our best efforts to secure the release of the above-mentioned subcontractor liens, and a definitive settlement agreement was executed on February 26, 2004. Algonquin Gas Transmission paid the settlement amount of $37 million to us in March 2004. This settlement was included in our reported results for fiscal year 2003. We also settled the related subcontractor litigation, and a related $28 million letter of credit was released in the second quarter of fiscal year 2004.

Other Matters

In connection with a major West African contract, we received a letter dated December 12, 2003 from the customer notifying us of a potential claim for an unspecified amount of liquidated damages. We believe that a settlement agreement with the customer has released us from any liability for liquidated damages, and no further action has been initiated in this regard by the customer. The customer issued a notice to the consortium, of which we are a member, rescinding the contract effective January 31, 2005. The notice claimed that the lack of performance in the 13-month period beginning December 31, 2003, was a fundamental breach that amounted to

repudiation of the contract. We completed our share of the offshore scope in December 2004 and expect to receive a handover certificate from the customer and therefore do not believe the notice will have any adverse impact on us. We have recorded no provision in connection with this contract.

We were informed by the SEC in December 2003 that it was conducting an informal inquiry into our revenue recognition policies and practices with respect to claims and variation orders. As requested by the SEC we voluntarily produced information and documents in response to the informal inquiry. We have had no contact with the SEC regarding this matter since July 2004.

On December 31, 2003, the pipelay ship the Seaway Polaris dropped a pipe which it was laying for the Bonga project in Nigeria. We have received reimbursement of $6.3 million under the customer’s all risk insurance policy, and have recorded a further $5.7 million receivable on the basis of a report from the customer’s loss adjuster. All costs incurred to repair the pipe were charged to expense in fiscal year 2004.

In addition, in the course of our business, we become involved in contract disputes from time-to-time due to the nature of our activities as a contracting business involved in several long-term projects at any given time. We make provisions to cover the expected risk of loss to the extent that negative outcomes are likely and reliable estimates can be made. However, the final outcomes of these contract disputes are subject to uncertainties as to whether or not they develop into a formal legal action and therefore the resulting liabilities may exceed the liability we may anticipate.

Furthermore, we are involved in legal proceedings from time to time incidental to the ordinary course of our business. Litigation is subject to many uncertainties, and the outcome of individual matters is not predictable with assurance. It is reasonably possible that the final resolution of any litigation could require us to make additional expenditures in excess of reserves that we may establish. In the ordinary course of business, various claims, suits and complaints have been filed against us in addition to the ones specifically referred to above. Although the final resolution of any such other matters could have a material effect on our operating results for a particular reporting period, we believe that they should not materially affect our consolidated financial position.

For accounting purposes, we expense legal costs as they are incurred.

Subsequent Events

Below is a summary of events that occurred after November 30, 2004 which we consider to be of significance.

On January 13, 2005, we announced that SNSA had sold the 79,414,260 Common Shares they previously held. As a result SNSA no longer owns any of our shares.

On January 19, 2005, we sold our interest in Paragon Engineering Services, Inc. to a subsidiary of AMEC plc, yielding a gain on sale of $2.1 million.

On February 2, 2005, we announced a number of changes in the composition of the board of directors following SNSA’s sale of its remaining interest in us. Jacob Stolt-Nielsen (Chairman) and Niels G. Stolt-Nielsen both decided to retire from the board of directors with immediate effect. These changes to the board in February 2005 resulted in the following composition of the board: Mark Woolveridge (chairman of the board), James Hurlock (deputy chairman of the board and chairman of the governance and nomination committee), Trond Ø. Westlie (chairman of the audit committee), J. Frithjof Skouverøe (chairman of the compensation committee), Haakon Lorentzen, George Doremus, and Tom Ehret (chief executive officer).

On April 12, 2005, we announced the agreement to sell to Cal Dive certain Conventional and shallow water IMR assets that work in the NAMEX region for proceeds of $125 million in cash. The assets involved include: The DLB 801 pipelay barge; the Seaway Kestrel; the Seaway Defender; the American Constitution; the American

Star; the American Triumph; the American Victory; the American Liberty; the American Diver; and the shore support bases at the Port of Iberia and Port Fourchon in Louisiana . We have made arrangements with Cal Dive to charter back the DLB 801 and the Seaway Kestrel for the duration of the ongoing Trinidad projects in 2005. The agreement with Cal Dive includes the sale of vessels which have been used as security for the $350 million revolving credit facility. Upon completion of the sale to Cal Dive, the limit of the $350 million revolving credit facility will be reduced to $313 million unless and until we replace the sold assets with assets of an equivalent value. The closing of the transaction is subject to customary regulatory approvals, including under the HSR Act. On May 25, 2005, we received a request from the U.S. Department of Justice for additional information in connection with its review of the transaction under the HSR Act, to which we intend to respond promptly.

On May 9, 2005, the pipelay ship Seaway Polaris dropped a cable that was being installed as part of a West African project causing some damage to the barge and some delays in the project. Management is currently assessing the impact of this event on our financial results.

Research and Development and Intellectual Property

To support our engineering and operational activities, we hold a number of patents, trademarks, software and other intellectual property. We have 68 patents in force in 21 countries and currently a portfolio of 85 additional developments under patent application. A limited number of our patents are held in common with other industrial partners. We also conduct some of our operations under licensing agreements, allowing us to make use of specific techniques or equipment patented by third parties. We do not consider that any one patent or technology represents a significant percentage of our net operating revenue. In March 2004 we settled a dispute with a competitor who was claiming damages for infringement of a patented technology.

Our research and development programs have concentrated both on the requirements of our customers, who are constantly seeking to develop oil and gas reserves in deeper waters, and increasing the efficiency of our offshore equipment and operations. We have research and development programs aimed at developing new and extending existing technology for the installation, repair and maintenance of offshore structures, particularly in ultra deep water (beyond 1,500 meters). Recent successes include the riser bundle tower system, which was designed, built, and installed in 1,400 meters of water for the Girassol project in Angola, and the Deep MATIS ^™ pipeline connection system. Our research and development activities are in general carried out internally using both dedicated research personnel and as part of specific projects. Where appropriate, external research and development is performed either through strategic technological alliances or joint industry collaborative projects. Our expenditures on company-sponsored research and development were approximately $1 million in each of fiscal years 2004, 2003 and 2002.

Inflation

Our business transactions in high-inflation countries are substantially denominated in stable currencies, such as the U.S. dollar, and inflation therefore does not materially affect the consolidated financial results.

Impact of New Accounting Standards

Stock-Based Compensation

On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004) (“SFAS No. 123(R)”), “Share-Based Payment” which is a revision of SFAS No. 123 “Accounting for Stock-Based Compensation.” SFAS No. 123(R) supersedes APB No. 25 and amends SFAS No. 95 “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. The pro forma disclosure of fair values allowed under SFAS No.123 is no longer an alternative.

SFAS No. 123(R) is required to be adopted in the first fiscal year commencing after June 15, 2005, and we expect to adopt it from December 1, 2005. We have not yet completed our assessment of the impact of adoption

of this standard on the results for fiscal year 2006. We have elected not to restate our previously issued results for the portion of awards that had vested at the date of adoption and so no restatement of prior periods will be made.

Exchanges of Non-Monetary Assets

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No.153 “ Exchanges of Non-monetary Assets—An Amendment of APB Opinion No. 29”. (“SFAS No. 153”). SFAS No. 153 eliminates the exception to fair value accounting for exchanges of similar productive assets contained in Accounting Principles Board Opinion No. 29 (“APB No. 29”), and replaces it with a general exception for exchange transactions that do not have commercial substance. The exception in APB No. 29 required certain non-monetary asset exchanges to be recorded on a carryover basis with no gain/loss recognition. Under SFAS No 153, exchange transactions with commercial substance are required to be accounted for at fair value with gain/loss recognition on assets surrendered in exchange transactions. We will be required to adopt SFAS No. 153 in the first fiscal year beginning after June 15, 2005, and believe the adoption of this standard will not have a material impact on our financial statements.

International Financial Reporting Standards

U.S. GAAP will continue to be the primary reporting framework for Stolt Offshore, most probably until the year ended November 30, 2008, as we are domiciled and registered in Luxembourg and the Luxembourg authorities are expected to confirm the anticipated decision to grant exemption until the accounting period beginning on or after January 1, 2007 from the requirement to adopt International Financial Reporting Standards.

Changes in Share Capital

At an Extraordinary General Meeting on February 11, 2004 our authorized share capital was increased to 230,000,000 Common Shares, with a par value of $2.00 per share.

During fiscal year 2004, the following transactions occurred:

•

On February 13, 2004, we issued and sold 45.5 million Common Shares at $2.20 per share, resulting in gross proceeds of $100.1 million ($93.2 million net of expenses);

•

On February 13, 2004, we issued 17 million new Common Shares to Stolt-Nielsen Transportation Group Ltd. (“SNTG”), a subsidiary of SNSA, upon conversion of all of our outstanding Class B Shares to Common Shares held by SNTG;

•

On April 20, 2004, we issued 22.7 million Common Shares to SNTG or its subsidiary in consideration for the cancellation of the $50 million subordinated note from SNTG to us, representing a price of $2.20 per share; and

•

On May 25, 2004, we issued and sold 29.9 million Common Shares at $2.20 per share, raising gross proceeds of $ 65.8 million ($61.6 million net of expenses).

As at November 30, 2004 there were 190.5 million outstanding Common Shares, of which SNSA owned 79.4 million Common Shares or 41.7%. As described above and in Note 29 to the Consolidated Financial Statements, SNSA sold its entire shareholding effective January 13, 2005 and thereby ceased to be a shareholder of our company.

Related Party Transactions

See Item 7. “Major Shareholders and Related Party Transactions—Relationship with SNSA.”

BROKERAGE PARTNERS
<a href='http://addelivery.thestreet.com/ck.php?n=a5201ff0&cb=104' target='_blank'><img src='http://addelivery.thestreet.com/avw.php?zoneid=58&cb=104&n=a5201ff0' border='0' alt='' /></a>	<a href='http://addelivery.thestreet.com/ck.php?n=a832d98e&cb=100' target='_blank'><img src='http://addelivery.thestreet.com/avw.php?zoneid=59&cb=100&n=a832d98e' border='0' alt='' /></a>
<a href='http://addelivery.thestreet.com/ck.php?n=ac9d3d19&cb=109' target='_blank'><img src='http://addelivery.thestreet.com/avw.php?zoneid=60&cb=109&n=ac9d3d19' border='0' alt='' /></a>	<a href='http://addelivery.thestreet.com/ck.php?n=ada6d0a9&cb=241' target='_blank'><img src='http://addelivery.thestreet.com/avw.php?zoneid=61&cb=241&n=ada6d0a9' border='0' alt='' /></a>
<a href='http://addelivery.thestreet.com/ck.php?n=a99d64d4&cb=513' target='_blank'><img src='http://addelivery.thestreet.com/avw.php?zoneid=62&cb=513&n=a99d64d4' border='0' alt='' /></a>	<a href='http://addelivery.thestreet.com/ck.php?n=acd611b7&cb=989' target='_blank'><img src='http://addelivery.thestreet.com/avw.php?zoneid=63&cb=989&n=acd611b7' border='0' alt='' /></a>

Utilization Rate

For the year ended November 30,

Deepwater and heavy construction ships

Light construction and survey ships

Trunkline barges and anchor ships