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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16 OF
THE SECURITIES EXCHANGE ACT OF 1934
For the period ended June 30, 2003

Aurelia Energy N.V.

(Translation of registrant's name into English)

Landhuis Joonchi
Kaya Richard J. Beaujon z/n
Curaçao, Netherlands Antilles
(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover
Form 20-F or Form 40-F.

Form 20-F ý Form 40-F o

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): o

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes o ý No

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b).

Not Applicable.

Aurelia Energy N.V.

Quarterly Report
For period ended June 30, 2003

Dated August 28, 2003

TABLE OF CONTENTS

		Page
CERTAIN DEFINITIONS		2
FORWARD-LOOKING STATEMENTS		2
UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	UNAUDITED INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS	4
	UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF INCOME	6
	UNAUDITED INTERIM CONDENSED CONSOLIDATED CASH FLOW STATEMENT	7
NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS		8
UNAUDITED OTHER FINANCIAL DATA AND RATIOS		15
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17

CERTAIN DEFINITIONS

We have prepared this report using a number of conventions, which you should consider when reading the information contained herein. When we use the terms "we", "us", "our" and words of similar import, we are referring to Aurelia Energy N.V., itself, or to Aurelia Energy N.V. and its consolidated subsidiaries, as the context requires.

References to "dollars", "U.S. dollars" and "U.S.$" are to the currency of the United States, references to "euro" and "€" are to the single currency of the member states of the European Communities that have adopted the euro as their lawful currency under the legislation of the European Community relating to the Economic and Monetary Union and references to "£" and "sterling" are to the currency of the United Kingdom. In this report, we have translated certain euro amounts into U.S. dollars at exchange rates of €1.00 to U.S.$1.0485 and €1.00 to U.S.$1.1502, which were the noon buying rates in New York City for cable transfers in those currencies as certified for customs purposes by the Federal Reserve Bank of New York on December 31, 2002 and June 30, 2003, respectively, and we have translated certain sterling amounts into U.S. dollars at exchange rates of £1.00 to U.S.$1.6095 and £1.00 to U.S.$1.6529, which were the noon buying rates in New York City for cable transfers in those foreign currencies as certified for customs purposes by the Federal Reserve Bank of New York on December 31, 2002 and June 30, 2003, respectively, in each case, solely for the convenience of the reader. You should not construe these translations as representations that the euro or sterling amounts actually represent such U.S. dollar amounts or that we could convert these amounts into U.S. dollars at the rates indicated. On August 27, 2003 the applicable noon buying rates were €1.00 to U.S.$1.0906 and £1.00 to U.S.$1.5746.

FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements within the meaning of, and which have been made pursuant to, the U.S. Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact contained in this report, including, without limitation, those regarding our future financial position and results of operations, our strategy, plans, objectives, goals and targets, future developments in the markets where we participate or are seeking to participate, and any statements preceded by, followed by or that include the words "believe", "expect", "aim", "intend", "will", "may", "anticipate", "seek" or similar expressions or the negative thereof, are forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors, some of which are beyond our control, which may cause our actual results, performance or achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. These forward-looking statements are based on numerous assumptions regarding our present and future business strategies and the environment in which we will operate in the future. Important factors that could cause our actual results, performance or achievements to differ materially from those in the forward-looking statements include, among others:

•: the level of oil reserves contained in the oil fields on which we operate our FPSOs and the performance of those fields in general;
•: levels of capital expenditures by the oil industry on offshore exploration and production activities;
•: our future capital needs;
•: our ability to enter into new service agreements for our FPSOs, including the Munin, upon the termination of their existing service agreements;
•: the extent and nature of, and the efficacy of measures that we have implemented to limit, the delays and cost overruns associated with our redeployment of the Glas Dowr;

•: the outcome of our discussions with tax authorities with respect to our internal restructuring and our 1997, 1998, 1999 and 2000 tax years;
•: our ability to manage currency risks;
•: our ability to comply with existing or newly implemented environmental regimes in the countries in which we operate;
•: our ability to obtain, maintain and renew the permits and other governmental authorizations required to conduct our operations;
•: our liability for violations, known and unknown, under environmental laws;
•: our ability to complete existing and future projects on schedule and within budget;
•: our ability to comply with health and safety regulations at our facilities;
•: our ability to remain competitive and profitable;
•: the performance of oil companies to whom we contract our FPSOs;
•: the efficacy of modifications to our FPSOs;
•: our ability to compete in a competitive and changing marketplace;
•: our losses from operational hazards and uninsured risks;
•: our ability to minimize the downtime of FPSOs during periods of repair, maintenance, inclement weather and turnarounds;
•: our ability to protect our know-how and intellectual property;
•: the adverse impact of strikes, lock-outs and other industrial actions;
•: the possible extensions of our service agreements and certain of our material contracts;
•: our ability to tie-back additional oil fields that neighbor the oil fields on which our FPSOs operate; and
•: limitations on our operational flexibility arising under agreements governing our debt.

These forward-looking statements speak only as of the date of this report. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report might not occur.

UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AURELIA ENERGY N.V.

UNAUDITED INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS

		Note	At June 30, 2003	At December 31, 2002
			(unaudited)	(audited)
			(in U.S.$ thousands)
ASSETS
Current assets
Cash and cash equivalents
	Cash		12,587	22,576
	Deposits		497	448

			13,084	23,024

Accounts receivable
	Trade, net		65,321	27,963
	Related party		93	89
Other receivables			7,530	4,716
Prepaid expenses			5,071	5,376

			78,015	38,144

Inventory
	Work in process		2,717	11,789

			93,816	72,957

Non-current assets
Restricted deposits			85,326	82,491
Fixed assets
	Tangible fixed assets, net	2
	FPSOs		984,511	954,755
	Other tangible fixed assets		63,669	64,030
Income tax receivable			2,608	1,368
Deferred income taxes		10	98,958	84,970
Debt arrangement fees			19,460	19,249

			1,254,532	1,206,863

			1,348,348	1,279,820

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

AURELIA ENERGY N.V.

UNAUDITED INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS

	Note	At June 30, 2003		At December 31, 2002
		(unaudited)		(audited)
		(in U.S.$ thousands)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Accounts payable		16,300		21,554
Related party		125		125
Income taxes		1,740		1,871
Wage taxes and social security contributions		812		1,672
Other liabilities and accrued expenses		51,477		34,473
Billings in excess of cost and unrealized income		13,753		1,958

		84,207		61,653

Non-current liabilities
Long-term bank loans	3	264,567		324,733
10¹/4% Senior Notes due 2012	4	339,464		256,370
Long-term loan, related party	5	130,218		125,849
Tax lease benefits liability	6	41,686		39,395
Interest rate swaps		5,541		7,736
Pensions		4,337		3,893

		785,813		757,976

Shareholder's equity
Shares		170,000		170,000
Retained earnings		330,175		315,938
Accumulated other comprehensive income	9	(21,847	)	(25,747	)

		478,328		460,191

		1,348,348		1,279,820

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

AURELIA ENERGY N.V.

UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF INCOME

		For the six months ended June 30,				For the three months ended June 30,
	Note	2003		2002		2003		2002
		(in U.S.$ thousands except share and per share amounts)
Revenues	7	143,750		124,959		87,650		68,897

Operating expenses
Operations expenses	8	91,062		63,310		61,648		36,146
Selling, general and administrative expenses		5,514		5,232		3,083		2,690
Depreciation of tangible fixed assets		25,925		27,736		12,973		13,933
Other operating income		(2,016	)	(1,424	)	(1,023	)	(1,027	)

		120,485		94,854		76,681		51,742

Operating income		23,265		30,105		10,969		17,155

Financial income (expense)
Interest income		1,714		1,946		886		996
Interest expense		(22,962	)	(23,926	)	(11,859	)	(13,634	)
Currency exchange results		987		(261	)	2,404		229

		(20,261	)	(22,241	)	(8,569	)	(12,409	)

Income before income taxes		3,004		7,864		2,400		4,746
Income taxes	10	(13,902	)	(11,374	)	(6,704	)	(5,193	)

Net income		16,906		19,238		9,104		9,939

Basic and diluted earnings per common share		124		141		67		73

Weighted average number of common shares outstanding		136,000		136,000		136,000		136,000

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

AURELIA ENERGY N.V.

UNAUDITED INTERIM CONDENSED CONSOLIDATED CASH FLOW STATEMENT

	For the six months ended June 30,
	2003		2002
	(in U.S.$ thousands)
Net income	16,906		19,238
Depreciation of tangible fixed assets	25,925		27,736
Increase in deferred tax assets	(13,988	)	(12,841	)
Amortization of debt arrangement fees	1,271		336
Amortization of discount on 10¹/4% Senior Notes due 2012	192		(3,829	)
Interest on long-term loan from related party	4,369		4,083
Change in pension provision	444		920
Tax effect on other comprehensive income	(769	)	—
Addition provision for uncollectible accounts receivable	(36	)	218
Change in operating assets and liabilities	(9,639	)	16,204

Net cash provided by operating activities	24,675		52,065
Net cash used in investing activities	(55,320	)	(40,531	)
Proceeds from long term and short term loans from banks and third parties	166,426		588,900
Proceeds from issuance of 10¹/4% Senior Notes due 2012	75,375		259,851
Proceeds from unwinding swap transaction	7,600		—
Redemption of loans and short term bank liabilities	(226,665	)	(835,367	)
Debt arrangement fees	(1,482	)	—
Other changes in financing activities	(354	)	(18,921	)

Net cash provided by financing activities	20,900		(5,537	)
Translation differences	(195	)	(23	)

Net increase/(decrease) in available cash and cash equivalents	(9,940	)	5,974
Cash and cash equivalents at beginning of year	23,024		15,713

Cash and cash equivalents at end of period	13,084		21,687

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

AURELIA ENERGY N.V.

NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS AND THREE MONTHS ENDED JUNE 30, 2003 AND 2002

1 Accounting Principles

The accompanying unaudited interim condensed consolidated financial statements have been prepared by the Company in accordance with U.S. Generally Accepted Accounting Principles (U.S. GAAP). The information furnished in the condensed consolidated financial statements includes normal recurring adjustments and reflects all adjustments which are, in the opinion of management, necessary for fair presentation of such financial statements. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted. Although the Company believes that the disclosures are adequate to make the information presented not misleading, it is suggested that these interim condensed consolidated financial statements be read in conjunction with the audited financial statements and the notes thereto for the year ended December 31, 2002.

Sales and operating results for the six months and the three months ended June 30, 2003 are not necessarily indicative of the results to be expected for the full year.

2 Tangible Fixed Assets

During the six months ended June 30, 2003 and the three months ended June 30, 2003, the Company invested U.S.$55.3 million and U.S.$21.4 million, respectively, in tangible fixed assets (as compared to U.S.$40.5 million and U.S.$29.8 million in the six months ended June 30, 2002 and in the three months ended June 30, 2002, respectively). The investment during the six months ended June 30, 2003 consisted primarily of U.S.$55.4 million for work performed in connection with the redeployment of the Glas Dowr to the Sable Field. Approximately U.S.$0.7 million related to the investment in a stock buoy, approximately U.S.$0.9 million related to lay-up costs of the Aoka Mizu and expenditures on certain office equipment, approximately U.S.$(1.4) million relates to a lease buoy sold to the client Unocal, and approximately U.S.$(0.3) million relates to an adjustment to the purchase price of the Haewene Brim. The investment during the three months ended June 30, 2003 consisted primarily of U.S.$21.7 million for work performed in connection with the redeployment of the Glas Dowr to the Sable Field. Approximately U.S.$0.4 million related to the investment in a stock buoy, approximately U.S.$0.7 million related to lay-up costs of the Aoka Mizu and expenditures on certain office equipment, and approximately U.S.$(1.4) million related to a lease buoy sold to the client Unocal.

3 Long-Term Bank Loans

At January 28, 2002, the Company refinanced its outstanding debt under a U.S.$450.0 million revolving corporate credit facility and its outstanding debt under a U.S.$288.0 million bridge credit facility with funds drawn under an 8-year, U.S.$600.0 million credit facility. The new replacement credit facility can be used to finance the construction of new FPSOs and, to a limited extent, for general corporate purposes. Interest is payable at a rate that is equal to a specified margin over LIBOR. The margin, which is currently 1.400%, varies from 1.300% to 1.700% depending, among other factors, on the amount outstanding under the facility. At June 30, 2003 the interest rate, including margin, was 2.48%. The costs incurred in arranging the credit facility have been capitalized as debt arrangement fees under non-current assets and will be amortized over the term of the facility. The facility is primarily secured with mortgages over the FPSOs and assignments of incoming cash flows generated from contracts with customers concerning the FPSOs.

4 10¹/4% Senior Notes due 2012

In February 2002, the Company issued U.S.$260.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012 through its finance subsidiary, Bluewater Finance Limited, at a price of 98.47% of the principal amount thereof. The Company used the gross proceeds from the issuance to repay approximately U.S.$248.5 million of indebtedness outstanding under its replacement credit facility and to pay approximately U.S.$7.5 million of costs relating to the issuance. The Company and each of its direct and indirect subsidiaries (other than Bluewater Finance Limited and Brightfield Corporation (a subsidiary in liquidation with no material assets, liabilities or operations)) have fully and unconditionally guaranteed the 10¹/4% Senior Notes due 2012 on a joint and several basis.

In April 2003, the Company issued an additional U.S.$75.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012 through its finance subsidiary, Bluewater Finance Limited, at a price of 100.5% of the aggregate principal amount thereof plus accrued interest from and including February 15, 2003 to but excluding the issue date. The Company used approximately U.S.$75.4 million of the gross proceeds from the issuance, excluding the accrued interest from and including February 15, 2003 to but excluding the issue date, to repay approximately U.S.$73.4 million of indebtedness outstanding under its replacement credit facility and to pay an estimated U.S.$2.0 million of costs relating to the issuance.

Bluewater Finance Limited is a wholly owned finance subsidiary of the Company and each other subsidiary of the Company is wholly-owned, directly or indirectly, by the Company. The Company has no independent assets or operations. There are no significant restrictions on the ability of the Company or any other guarantor of the 10¹/4% Senior Notes due 2012 to obtain funds from its subsidiaries by dividend or loan. Neither Bluewater Finance Limited nor any of the guarantors of the 10¹/4% Senior Notes due 2012 (other than the Company) are restricted by any third party in their ability to transfer funds within the meaning of Rule 4-08(e)(3) of Regulation S-X. As a result, the guarantees of the 10¹/4% Senior Notes due 2012 meet the conditions of Rule 3-10(d) of Regulation S-X. The fair value of the 10¹/4% Senior Notes due 2012 at June 30, 2003 amounts to U.S.$333.3 million and is based on the quoted market price.

To reduce the interest expense relating to the 10¹/4% Senior Notes due 2012, the Company entered into a fixed-to-floating interest rate swap transaction, with effect from April 25, 2003, that enabled the Company to swap the equivalent of the fixed rate amount of interest that is payable on U.S.$335.0 million aggregate principal amount of the 10¹/4% Senior Notes due 2012 for the floating rate amount of interest that would be payable on an equal amount of indebtedness. On May 27, 2003, the Company cancelled the swap transaction. Under the swap, prior to the cancellation, the Company received interest payments that were calculated at a fixed rate of 10¹/4% and made interest payments that were calculated at a floating rate that was equal to a margin over LIBOR. The Company received U.S.$7.6 million on May 30, 2003, which represented its net gain from the cancellation of the swap transaction. The Company deferred this gain, which will be credited to the income statement over the remaining duration of the 10¹/4% Senior Notes due 2012, and used this payment to repay outstanding indebtedness under its replacement credit facility.

the Company will receive payments that are calculated at a fixed rate of 10¹/4% and makes interest payments that are calculated at a floating rate that is equal to a margin of 6.11% over LIBOR.

5 Long-Term Loan, Related Party

The fair value of the long-term loan from the related party Marenco Investments Limited at June 30, 2003 and December 31, 2002 amounted to U.S.$161.7 million and U.S.$160.6 million, respectively. The fair value as of June 30, 2003 has been determined by an independent bank, based on the discounted cash-flow method assuming redemption in five equal annual installments as from December 2012. The terms and conditions of the loan remained unchanged compared to those disclosed in the audited financial statements as of and for the year ended December 31, 2002.

6 Tax Lease Benefits Liability

The liability to repay tax leases increased by U.S.$2.3 million in the six months ended June 30, 2003 and increased by U.S.$4.4 million in the three months ended June 30, 2003. This tax lease benefits liability increased as a result of the tax lease on the topsides of the Haewene Brim and was partially compensated by a reduction in the amount of the liability for the repayment to the lessor in the event of a voluntary early termination of the tax lease arrangements and because of fluctuations in currency exchange rates and market interest rates.

7 Segment Information

The segment information by business segment is as follows:

		For the six months ended June 30,				For the three months ended June 30,
		2003		2002		2003		2002
		(in U.S.$ thousands)
FPSO
	Revenues	133,192		103,570		82,437		53,870
	Segment net income	20,789		28,214		9,741		13,640
	Identifiable assets	1,327,833		1,206,874		1,327,833		1,206,874
	Capital expenditures	54,167		40,191		20,720		29,641
	Depreciation and amortization	25,628		27,124		12,831		13,568
	Interest income and (expense)	(21,256	)	(21,730	)	(11,102	)	(12,984	)
	Income tax expense (benefit)	(12,618	)	(10,284	)	(6,087	)	(4,695	)
SPM
	Revenues	10,558		21,389		5,213		15,027
	Segment net income	(3,883	)	(8,976	)	(637	)	(3,701	)
	Identifiable assets	19,925		21,788		19,925		21,788
	Capital expenditures	1,153		340		705		119
	Depreciation and amortization	297		612		142		365
	Interest income and (expense)	8		(250	)	129		346
	Income tax expense (benefit)	(1,284	)	(1,090	)	(617	)	(498	)
Other
	Identifiable assets	590		468		590		468
Consolidated
	Revenues	143,750		124,959		87,650		68,897
	Segment net income	16,906		19,238		9,104		9,939
	Identifiable assets	1,348,348		1,229,130		1,348,348		1,229,130
	Capital expenditures	55,320		40,531		21,173		29,760
	Depreciation and amortization	25,925		27,736		12,973		13,933
	Interest income and (expense)	(21,248	)	(21,980	)	(10,973	)	(12,638	)
	Income tax expense (benefit)	(13,902	)	(11,374	)	(6,704	)	(5,193	)

The Company has changed its method to allocate costs between the FPSO segment and the SPM segment as of January 1, 2003. The comparative figures have not been adjusted for this new allocation method.

8 Operations Expenses

Operations expenses are as follows:

	For the six months ended June 30,		For the three months ended June 30,
	2003	2002	2003	2002
	(in U.S.$ thousands)
SPM contracts	14,508	28,371	5,894	17,823
FPSO contracts	76,554	34,939	55,754	18,323

	91,062	63,310	61,648	36,146

9 Other Comprehensive Income

Other comprehensive income is as follows:

	For the six months ended June 30,			For the three months ended June 30,
	2003		2002	2003		2002
	(in U.S.$ thousands)
Decrease in fair value of cash flow hedges	2,195		419	1,100		(330	)
Tax effect	(769	)	—	(385	)	—
Translation result	(195	)	23	(241	)	141

	1,231		442	474		(189	)

10 Income Taxes

Effective January 1, 2000, Bluewater entered into an internal restructuring process. In connection therewith, the economic interests in most of the assets and liabilities of certain non-Dutch consolidated group companies (the "selling companies") were sold to the Company, while legal title to the assets and liabilities transferred remained with the selling entities. The valuation of the assets and liabilities transferred was based on a valuation report prepared by an independent investment bank. The sales of these economic interests resulted for income taxes purposes only in intercompany profits at the level of the selling companies and the creation of a corresponding amount of goodwill and intercompany indebtedness at the level of the Company. Although extensive discussions were held with the tax authorities on the tax structure of Bluewater and the internal restructuring, Bluewater's tax structure and the tax consequences of the internal restructuring became subject to a tax audit and remain subject to further review by the tax authorities.

In May 2002, the Company received a draft audit report from the Dutch tax authorities. The draft tax audit report included certain proposed factual findings relating to the issue of whether our non-Dutch group companies are residents of the Netherlands for Dutch tax purposes or have a taxable presence in the Netherlands. The draft audit report, which does not present a final determination by the Dutch tax authorities, states that it was issued for discussion purposes. On the basis of the draft tax report, the Dutch tax authorities assessed, in June 2002, additional taxes with respect to a Dutch group member for its 1998 and 1999 tax years and assessed, in November 2002, July 2003 and August 2003, additional taxes with respect to certain non-Dutch group members for their 1997, 1998, 1999 and 2000

tax years. The total amount of these assessments, including interest to their respective dates, was €52.9 million as of December 31, 2002 and €135.4 million as of June 30, 2003 (which amount includes additional assessments received in July and August 2003). The Company is in discussions with the Dutch tax authorities regarding these taxes and is vigorously contesting their assessment. The Company believes that the findings of fact and the relevant legal and regulatory interpretations upon which the Dutch tax authorities' position is based are incomplete and incorrect, and that the assessment of such additional taxes is contrary to certain favorable tax rulings, which it has received from them. In any event, the Company believes that any assessment of additional taxes is incorrect, and that it is likely that it will prevail on the merits in any final determination of the assessments. Accordingly, in July 2003, the Company filed with the Dutch tax authorities a response to their draft audit report and a transfer pricing report supporting the Company's response. The Company intends to continue to contest vigorously the imposition of any additional taxes and, if necessary, to seek administrative and judicial review of the assessments. Administrative and judicial review of the assessments in the Netherlands would likely take several years. The Company intends to withhold payment of such taxes pending final resolution of the issue. Although there can be no assurance that the relevant issues will ultimately be resolved in its favor, the Company believes that it is not probable that additional Dutch income taxes will be payable for the 1997, 1998, 1999 and 2000 tax years, and, accordingly, the Company did not accrue for the aforementioned tax assessments in these unaudited condensed consolidated financial statements.

In connection with the draft tax audit report, the Company is also in discussions with the Dutch tax authorities concerning its internal restructuring. In the course of such discussions, the Dutch tax authorities have confirmed to the Company that they will not seek to tax any capital gain that may be associated with the sale of relevant economic interests in connection with the Company's internal restructuring, but instead will focus their analysis only on the amount of goodwill and deductible interest related to the internal restructuring and the percentage of goodwill and deductible interest from the Company's internal restructuring that should ultimately be attributed to the Company's non-Dutch activities. The outcome of such discussions could limit the Company's ability to take advantage of future tax savings associated with its internal restructuring by limiting the amount of goodwill that the Company may amortize and the amount of interest it may deduct for tax purposes in future periods. However, based upon current facts and circumstances, applicable tax law, regulation and precedent, discussions with relevant tax authorities and professional advisers and other relevant criteria, the Company estimates that it is currently probable that it will realize benefits relating to at least U.S.$434.0 million of amortizable goodwill and at least U.S.$768.0 million of interest-bearing intercompany debt in connection with its internal restructuring at January 1, 2000 and that such amounts will result in tax losses which may be carried forward for Dutch income tax purposes. In addition, in December 2001, U.S.$379.5 million of the intercompany indebtedness of Bluewater Holding B.V. relating to the internal restructuring was converted to share capital, thereby reducing the amount of tax benefits that the Company may take advantage of in subsequent periods. Notwithstanding the Company's current estimate, however, it is impracticable to quantify definitively at this time the effect that the outcome of such discussions may have on the Company's actual tax position, because any such definitive quantification depends on a number of future events, including the specific factual findings and legal and regulatory positions that may be taken by the Dutch tax authorities in any possible future challenge to the Company's internal restructuring, as well as the outcome of any relevant proceedings.

11 Subsequent Events

Glas Dowr

From time to time, the Company is required to make capital expenditures in respect of its FPSOs and its SPM development projects. The Company's current commitments for these expenditures, and the majority of its expected expenditures for 2003, relate to modifications that it has been required to make to the Glas Dowr's topsides and mooring system and work that it has been required to perform at the Sable Field to prepare the Glas Dowr for its redeployment to the location.

After redeployment from the North Sea, the Glas Dowr commenced production on August 7, 2003 on the Sable Field off South Africa. In connection with the commencement of production, the Company entered into a temporary arrangement pursuant to which it earns day rates under the service agreement while continuing to address various technical issues of concern to PetroSA. The arrangement provides for the payment to the Company of fees on the same basis as in the service agreement, subject to a reduction of the Company's fixed operating fee and fixed shuttle tanker fee (as well as its fixed facility fee) according to a predetermined schedule if oil production and gas and water reinjection uptimes of the Glas Dowr fall below 95%, unless otherwise agreed with PetroSA. Due to an unanticipated increase in the scope and complexity of the vessel modifications, labor unrest and difficulties with project management on the part of the construction yard where the work was performed, the project experienced delays and cost overruns. The delay in the commencement of production and additional work on the gas compression facilities, along with increased insurance costs resulted in an upward revision in the Company's estimate of the costs of the vessel modifications and subsea work, excluding exchange rate differences and financing costs, to approximately U.S.$195.7 million. Of this amount, U.S.$50.4 million is reimbursable by PetroSA. As of June 30, 2003, the Company had expended approximately U.S.$133.7 million on the vessel modifications and approximately U.S.$38.6 million on developing the subsea infrastructure, and it had received approximately U.S.$38.6 million in milestone payments from PetroSA for the completion of the subsea work. Based upon its estimates, the Company believes that it has approximately U.S.$23.7 million in remaining commitments for expenditures, excluding exchange rate differences and financing costs, relating to the project as of that date. The Company expects to fund U.S.$11.9 million of the expenditures with milestone payments that it will receive from PetroSA for remaining subsea work and to fund the remaining expenditures with borrowings under its replacement credit facility. The Company does not expect the delays or budgetary overruns to otherwise materially affect its liquidity or capital resources. In addition to the cost of vessel modifications and subsea work, U.S.$8.5 million has been capitalized for financing costs and U.S.$9.7 million for operational support, and U.S.$2.6 million for exchange rate losses resulting from the difference between the project exchange rate and actual exchange rates. The total capitalized cost for the Glas Dowr project at June 30, 2003 was U.S.$154.5 million.

Interest Rate Swap

As of July 17, 2003 the Company re-entered into a fixed-to-floating interest rate swap transaction that enables the Company to swap the equivalents of the fixed rate amount of interest that is payable on U.S.$335.0 million aggregate principal amount of the 10¹/4% Senior Notes due 2012 for a floating rate amount of interest that would be payable on an equal amount of indebtedness. Under the swap, the Company will receive payments that are calculated at a fixed rate of 10¹/4% and makes interest payments that are calculated at a floating rate that is equal to a margin of 6.11% over LIBOR.

UNAUDITED OTHER FINANCIAL DATA AND RATIOS

		For the six months ended June 30,				For the three months ended June 30,
		2003		2002		2003		2002
		(in U.S.$ thousands, except ratios)
EBITDA⁽¹⁾
	FPSO business	53,968		66,550		25,086		34,773
	SPM business	(4,778	)	(8,709	)	(1,144	)	(3,685	)

	Total	49,190		57,841		23,942		31,088

Capital expenditures, net⁽²⁾		55,320		40,531		21,173		29,760
Cash interest paid⁽³⁾		23,525		19,701		12,950		11,500
Ratio of EBITDA to cash interest paid		2.09x		2.94x		1.85x		2.70x
Ratio of earnings to fixed charges⁽⁴⁾		—		1.37x		1.04x		1.38x

Notes:

(1): "EBITDA" is defined as operating income (loss) plus depreciation and amortization. EBITDA is presented as additional information because we believe that it is a useful measure for certain investors to determine our operating cash flow and historical ability to meet debt service and capital expenditure requirements. We also believe that it provides a useful measure of the level of profitability we achieve with our asset base. EBITDA is not a measure of financial performance under U.S. GAAP and should not be considered as an alternative to cash flow from operating activities, a measure of liquidity or an alternative to net income as indicators of our operating performance or any other measures of performance derived in accordance with U.S. GAAP. The following table presents a reconciliation of our EBITDA to net income and net cash provided by operating activities for the periods indicated.

	For the six months ended June 30,				For the three months ended June 30,
	2003		2002		2003		2002
	(in U.S.$ thousands)
EBITDA	49,190		57,841		23,942		31,088
Depreciation of tangible fixed assets and amortization of intangible assets	25,925		27,736		12,973		13,933
Financial income and expense	(20,261	)	(22,241	)	(8,569	)	(12,409	)
Income taxes	(13,902	)	(11,374	)	(6,704	)	(5,193	)

Net income	16,906		19,238		9,104		9,939
Adjustments to reconcile net income to cash provided	17,408		16,623		9,042		6,856
Changes in operating assets and liabilities, net of effect of acquisitions	(9,639	)	16,204		10,281		4,132

Net cash provided by (used in) operating activities	24,675		52,065		28,427		20,927

(2): "Capital expenditures, net" represents additions to fixed assets less disposals of fixed assets and excludes our acquisitions of the Haewene Brim, the Munin and their related operating companies.
(3): "Cash interest paid" is defined as interest expense, plus capitalized interest, less accrued interest on the subordinated and unsubordinated Marenco loans and less amortization of debt arrangement fees.
(4): The term "earnings" is the amount of pre-tax income from continuing operations before adjustment for minority interests in consolidated subsidiaries or income or loss from equity

investees, plus fixed charges, plus amortization of capitalized interest, plus distributed income to equity investees, plus the share of pre-tax losses of equity investees for which charges arising from guarantees are included in fixed charges, less interest capitalized, less preference security dividend requirements of consolidated subsidiaries, less the minority interest in pre-tax income of subsidiaries that have not incurred fixed charges. The term "fixed charges" means the sum of the following: (a) interest expensed or capitalized, (b) amortized premiums, discounts and capitalized expenses related to indebtedness, (c) an estimate of the interest within rental expense, and (d) preference security dividend requirements of consolidated subsidiaries. The term "preference security dividend" is the amount of pre-tax earnings that is required to pay the dividends on outstanding preference securities, computed as the amount of the dividend divided by one minus the effective income tax rate applicable to continuing operations. For the six months ended June 30, 2003 there was a deficiency of earnings to fixed charges of U.S.$0.2 million.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

The following management's discussion and analysis of financial condition and results of operations should be read in conjunction with the unaudited interim condensed consolidated financial statements and the related notes thereto included elsewhere in this report. Our audited consolidated financial statements and unaudited interim condensed consolidated financial statements have been prepared in accordance with U.S. GAAP. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about us and our industry. These forward-looking statements involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those described under "Forward-Looking Statements" and elsewhere in this report, as well as in our annual report for the year ended December 31, 2002.

Overview

We are Aurelia Energy N.V., a holding company with no independent operations, and its subsidiaries, a group of companies that comprise a specialized service provider to and operator in the offshore oil industry. We operate under the name "Bluewater" and are a leader in the design, development, ownership and operation of FPSOs, which we operate for oil companies under medium- and long-term service agreements, and the design, development, project management and delivery of SPM systems.

Our FPSO business earns revenues from the design, development and operation of FPSOs pursuant to medium- and long-term service agreements with oil companies. We treat our service agreements as "operating leases" under U.S. GAAP and present them as such in our consolidated financial statements. Under these agreements, we generally are paid a defined day rate consisting of a fixed facility fee that covers the rental of the FPSO and associated equipment and an indexed operating fee that covers the cost of operating, maintaining and insuring the vessel. We may also receive additional tariff payments based on oil or water production or gas lift volumes (or a combination of those volumes), bonus payments that relate to the prevailing price of oil and certain other fees. Our FPSO fleet currently consists of five high specification FPSOs (the Uisge Gorm, the Bleo Holm, the Glas Dowr, the Haewene Brim and the Munin) that we have contracted to oil companies under service agreements and two FPSO hulls (the Aoka Mizu and the Paradise) that we are marketing worldwide. In the six months ended June 30, 2003 and in the three months ended June 30, 2003, our FPSO business generated 92.7% and 94.1%, respectively, of our revenues, 123.0% and 107.0%, respectively, of our net income and 109.7% and 104.8%, respectively, of our EBITDA.

Our SPM business earns revenues from the design, development, project management and delivery of SPM systems under our SPM delivery contracts. We have developed a number of different types of SPM systems for oil companies and contractors around the world, resulting in the delivery of 3 SPM systems since 1999 and more than 50 SPM systems since our founding. Because SPM systems are integral to the operation of FPSOs in harsh environments, and because they form an important link in the oil production chain, we believe that it is important to preserve our core SPM capabilities for use in connection with future FPSO projects. In the six months ended June 30, 2003 and in the three months ended June 30, 2003, our SPM business generated 7.4% and 5.9%, respectively, of our revenues, (23.0)% and (7.0)%, respectively, of our net income, and (9.7)% and (4.8)%, respectively, of our EBITDA respectively.

While we manage FPSO and SPM projects from the initial design and engineering phase to final installation, we do not engage in the fabrication of FPSOs or SPM systems. Rather, we outsource these requirements to qualified subcontractors. In the six months ended June 30, 2003 and in the three months ended June 30, 2003, we had revenues of U.S.$143.8 million and U.S.$87.7 million, respectively,

operating income of U.S.$23.3 million and U.S.$11.0 million, respectively, net income of U.S.$16.9 million and U.S.$9.1 million, respectively, and EBITDA of U.S.$49.2 million and U.S.$23.9 million, respectively.

Seasonality

We believe that our business is not affected by seasonal weather conditions that impact some service providers to the offshore oil industry. While some service providers operating in harsh weather environments, such as the North Sea, are negatively affected in the first and fourth quarters by adverse weather conditions that prevent or limit the full operation of their crews or vessels, we generally do not experience material disruptions to our operations as a result of seasonal weather conditions. Our FPSOs have been developed using high environmental and design standards that generally permit them to fulfill their contractual uptime requirements even in harsh weather conditions. We also do not believe that our SPM business is affected by seasonal factors.

Oil Prices

We believe that the fixed nature of the payments that we receive under our service agreements significantly reduces the exposure of our FPSO business to fluctuations in oil prices during the minimum terms of our service agreements. Nevertheless, because oil prices affect the production economics at the fields on which our FPSOs operate, we believe that changes in oil prices may indirectly affect our FPSO business to the extent they affect the decisions of oil companies to continue production at fields nearing the end of their production profiles or to enter into tie-back arrangements with respect to marginal fields, each of which could affect the extension of our service agreements beyond their minimum terms. Changes in oil prices that impact levels of production could also affect the amount of tariff or bonus payments we earn under our service agreements. We expect that our FPSO business would be positively influenced in this regard by prolonged periods of high oil prices, but negatively affected by prolonged periods of depressed oil prices. In addition, we believe that oil prices may affect our ability to enter into new service agreements providing for the development of new FPSOs or the redeployment of our existing FPSOs upon the termination of their service agreements. We expect that there would be fewer short-term opportunities to enter into new service agreements during periods of low oil prices, but relatively more opportunities during periods of high oil prices. However, in each case, we believe that our FPSO fleet would have better deployment prospects than a number of newly-built FPSOs due to the fact that they may be contracted at more competitive rates (due to their accrued depreciation), their significantly shorter lead times to first oil and their high design standards.

We believe that our SPM business, which accounts for a relatively smaller proportion of our revenues, is generally more affected by fluctuations in oil price than our FPSO business due to the fact that SPM systems are generally developed for sale rather than leased on a term basis. Because oil companies generally adjust their spending on SPM systems based on trends in oil price, we would expect our SPM business to grow in response to positive developments in oil price and to decrease in response to negative developments in oil price. We believe that having a flexible and scalable workforce is an important factor in managing the costs associated with our more cyclical SPM business.

Operating Uptimes

We derive a substantial proportion of our total revenues from the payments that we receive from oil companies under our FPSO service agreements. The majority of these payments consist of defined day rates (consisting of a fixed facility fee and an indexed operating fee) and tariff payments (based on oil or water production or gas lift volumes or a combination of those volumes) whose economic terms are established prior to the commencement of operations under the service agreement. These day rates and tariff payments contributed U.S.$96.3 million and U.S.$47.3 million, to our total revenues in the six

months ended June 30, 2003 and in the three months ended June 30, 2003, respectively. Our total revenues were U.S.$143.8 million and U.S.$87.7 million in the six months ended June 30, 2003 and in the three months ended June 30, 2003, respectively. We believe that the most significant factor affecting the amount of these payments during a given contract period is the level of operating uptimes that our FPSOs maintain. Our service agreements currently require our FPSOs to maintain minimum operating uptimes that exceed certain thresholds. Depending on the particular service agreement, our facility fee or our operating fee may be adjusted to the extent that the relevant uptime exceeds or falls below the applicable threshold, and our tariff payments may be affected by consequential changes in oil or water production or gas lift volumes. When an FPSO is removed from the field as a result of factors unrelated to operating performance, our day rate is not adjusted based upon operating uptime. However, in such a case our day rate may be replaced by a lay-up rate (which could apply, among other times, in the event of poor field performance or periods of scheduled maintenance) or a force majeure rate (which could apply, among other times, in the event of a natural disaster, war or industrial action), depending, in each case, on the particular service agreement.

Insurance Costs

We maintain insurance coverage in such amounts as we believe to be prudent against normal risks in our operations, including, among other things, the risk of pollution and damage to vessels. Certain risks (such as business interruptions and environmental liabilities in excess of certain limits), however, are either not insurable or are insurable only at rates we consider uneconomical. The cost to obtain and maintain insurance could increase or decrease in the future for any number of reasons. In the aftermath of the events in the United States on September 11, 2001, we have experienced more than a 100.0% increase in the cost of our insurance premiums. While the increase in the price of insurance is recoverable in part under our service agreements with our customers, we account for the cost of insurance as an expense in our consolidated financial statements and the payments that we receive in respect of such expenses as revenues. There is no assurance that we will continue to maintain the same level of insurance coverage in the future or that we will be able to recover the cost of such coverage from our customers.

Redeployment of the Glas Dowr

After redeployment from the North Sea, the Glas Dowr commenced production on August 7, 2003 on the Sable Field off South Africa. In connection with the commencement of production, we entered into a temporary arrangement pursuant to which we earn day rates under the service agreement while continuing to address various technical issues of concern to PetroSA. The arrangement provides for the payment to us of fees on the same basis as in the service agreement, subject to a reduction of our fixed operating fee and fixed shuttle tanker fee (as well as our fixed facility fee) according to a predetermined schedule if oil production and gas and water reinjection uptimes of the Glas Dowr fall below 95%, unless otherwise agreed with PetroSA. Due to an unanticipated increase in the scope and complexity of the vessel modifications, labor unrest and difficulties with project management on the part of the construction yard where the work was performed, the project experienced delays and cost overruns. The delay in the commencement of production and additional work on the gas compression facilities, along with increased insurance costs resulted in an upward revision in our estimate of the costs of the vessel modifications and subsea work, excluding exchange rate differences and financing costs, to approximately U.S.$195.7 million. Of this amount, U.S.$50.4 million is reimbursable by PetroSA. As of June 30, 2003, we had expended approximately U.S.$133.7 million on the vessel modifications and approximately U.S.$38.6 million on developing the subsea infrastructure, and we have received approximately U.S.$38.6 million in milestone payments from PetroSA for the completion of the subsea work. Based upon our estimates, we believe that we have approximately U.S.$23.7 million in remaining commitments for expenditures, excluding exchange rate differences and financing costs, relating to the project as of that date. We expect to fund U.S.$11.9 million of the expenditures with

milestone payments that we will receive from PetroSA for remaining subsea work and to fund the remaining expenditures with borrowings under our replacement credit facility. We do not expect the delays or budgetary overruns to otherwise materially affect our liquidity or capital resources. In addition to the cost of vessel modifications and subsea work, U.S.$8.5 million has been capitalized for financing costs and U.S.$9.7 million for operational support, and U.S.$2.6 million for exchange rate losses resulting from the difference between the project exchange rate and actual exchange rates. The total capitalized cost for the Glas Dowr project at June 30, 2003 was U.S.$154.5 million.

Interest Expense

Our financial income and expense is primarily affected by our interest expense, which includes interest incurred on our credit facility, our 10¹/4% Senior Notes due 2012, the subordinated and unsubordinated Marenco loans and amortization of debt arrangement fees. Our interest expense does not include interest on financial debt relating to the construction or modification of FPSOs, which is capitalized and added to the historical cost of the FPSO to which it relates. Cash interest paid is defined as interest expense, plus capitalized interest, less accrued interest on the subordinated and unsubordinated Marenco loans and less amortization of debt arrangement fees. Our interest expense has increased since 2001 due to an increase in the amount of our outstanding indebtedness (which resulted from the incurrence of approximately U.S.$285.9 million of additional indebtedness in connection with our acquisitions of the Haewene Brim, the Munin and their related operating companies) and an increase in the weighted average interest rate payable in respect of our indebtedness (which resulted from the issuance of our 10¹/4% Senior Notes due 2012 at a relatively higher interest rate in each of February 2002 and April 2003 and from an increase in amortization of debt arrangement fees). This increase does not include our capitalized interest expense, which, in the six months and the three months ended June 30, 2003, related to modifications to the Glas Dowr and amounted to U.S.$4.9 million and U.S.$2.7 million, respectively.

To reduce the interest expense relating to our 10¹/4% Senior Notes due 2012, we entered into a fixed-to-floating interest rate swap transaction, with effect from April 25, 2003, that enabled us to swap the equivalent of the fixed rate amount of interest that is payable on U.S.$335.0 million aggregate principal amount of these 10¹/4% Senior Notes due 2012 for the floating rate amount of interest that would be payable on an equal amount of indebtedness. On May 27, 2003, we cancelled the swap transaction. Under the swap, prior to the cancellation, we received interest payments that were calculated at a fixed rate of 10¹/4% and made interest payments that were calculated at a floating rate that was equal to a margin over LIBOR. We received U.S.$7.6 million on May 30, 2003, which represented our net gain from the cancellation of the swap transaction. We deferred this gain, which will be credited to the income statement over the remaining duration of the 10¹/4% Senior Notes due 2012, and used this payment to repay outstanding indebtedness under our credit facility. As of July 17, 2003 we re-entered into a fixed-to-floating interest rate swap transaction that enables us to swap the equivalents of the fixed rate amount of interest that is payable on U.S.$335.0 million aggregate principal amount of the 10¹/4% Senior Notes due 2012 for a floating rate amount of interest that would be payable on an equal amount of indebtedness. Under the swap, we will receive payments that are calculated at a fixed rate of 10¹/4% and make interest payments that are calculated at a floating rate that is equal to a margin of 6.11% over LIBOR.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our unaudited condensed consolidated financial statements which have been prepared in accordance with U.S. Generally Accepted Accounting Principles. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities at the date of our financial

statements. Actual results may differ from these estimates under different assumptions or conditions. Critical accounting policies are defined as those policies which are reflective of significant judgments and uncertainties and which would potentially result in materially different results under different assumptions and conditions.

Revenue Recognition and Inventory

Our revenues consist of the contract payments that we receive under our FPSO service agreements and our SPM delivery contracts and the payments that we earn from the installation and mobilization of FPSOs and SPM systems. We recognize these revenues in the following manner.

Our service agreements are treated as "operating leases" under U.S. GAAP and presented as such in our consolidated financial statements. Under these agreements, we derive revenues from defined day rates, tariff payments, payments in respect of capital expenditures, payments for the rental of additional equipment and, in certain cases, bonus payments. Our day rates generally consist of a fixed facility fee (for the rental of the FPSO and associated equipment) and an indexed operating fee (covering the cost of operating, maintaining and insuring the vessel) and may be adjusted depending on the level of operating uptimes that we achieve. Our tariff payments are based on oil or water production or gas lift volumes or a combination of those volumes. Our bonus payments generally relate to the prevailing price of oil. We recognize revenues under our service agreements when the FPSO is made available and the relevant contract payments are based on a signed lease contract. We monitor changes in consumer price indices, uptime levels, production and lift volumes and oil prices on an ongoing basis and only include payments that depend on those factors in the determination of income when the relevant index is adjusted, the level of uptime is achieved, the necessary volume has been produced or lifted or the price of oil has changed. All other payments due under our service agreements are recognized on a straight-line basis over the term of the service agreement.

Under our SPM delivery contracts, we receive milestone payments from our customers for the design, engineering and management services that we provide during the progress of our SPM projects. We recognize revenues from the development of SPM systems and auxiliary equipment based on the percentage of completion method of accounting as the project is performed. Changes in project conditions are recognized in the period in which the revisions are determined. Our management identifies and estimates losses relating to uncompleted contracts and makes necessary provisions, if any, in the period in which the losses are determined. Differences between the actual and estimated development of our work in progress could materially impact the results of operations.

We recognize revenues from the installation and mobilization of FPSOs and SPM systems and from the provision of other services when the installation, mobilization or provision of services has been accepted by the customer and the collection of the receivable relating to the work is probable.

Income Taxes Payable

Our income tax charges are based on the tax regimes that are applicable to our group companies in the countries in which they are legally seated. We have historically benefited from low income taxes. While we believe that we will continue to benefit from a low level of income taxes in future years, as a result of the large amount of goodwill and deductible interest reported by certain members of our group for Dutch tax purposes, we received a draft tax audit report from the Dutch tax authorities in May 2002. The draft tax audit report included certain proposed factual findings relating to the issue of whether our non-Dutch companies are residents of the Netherlands for Dutch tax purposes or have a taxable presence in the Netherlands. The draft audit report, which does not represent a final determination by the Dutch tax authorities, states that it was issued for discussion purposes. On the basis of the draft audit report, the Dutch tax authorities assessed, in June 2002, additional taxes with respect to a Dutch group member for its 1998 and 1999 tax years and assessed, in November 2002,

July 2003 and August 2003, additional taxes with respect to certain non-Dutch group members for their 1997, 1998, 1999 and 2000 tax years. The total amount of these assessments, including interest to their respective dates, was €52.9 million as of December 31, 2002 and €135.4 million as of June 30, 2003 (which amount includes additional assessments received in July and August 2003). We are in discussions with the Dutch tax authorities regarding these taxes and are vigorously contesting their assessment. We believe that the findings of fact and the relevant legal and regulatory interpretations upon which the Dutch tax authorities' position is based are incomplete and incorrect, and that the assessment of such additional taxes is contrary to certain favorable tax rulings which we have received from them. In any event, we believe that any assessment of additional taxes is incorrect, and that it is likely that we will prevail on the merits in any final determination of the assessments. Accordingly, in July 2003, we filed with the Dutch tax authorities a response to their draft audit report and a transfer pricing report supporting our response. We intend to continue to contest vigorously the imposition of any additional taxes and, if necessary, to seek administrative and judicial review of the assessments. Administrative and judicial review of the assessments in the Netherlands would likely take several years. We intend to withhold payment of such taxes pending final resolution of the issue and have not established any accruals for these tax assessments. There can be no assurance, however, that the relevant issues will ultimately be resolved in our favor.

Deferred Income Taxes

Deferred income taxes are temporary differences between the tax bases of assets or liabilities and their reported amounts in our consolidated financial statements. Future tax benefits attributable to these differences are recognized to the extent that realization of the benefits is more likely than not. We recorded deferred income tax assets of U.S.$25.9 million in 2002, U.S.$14.8 million in the six months ended June 30, 2003 and U.S.$7.1 million in the three months ended June 30, 2003 which resulted primarily from the amortization of goodwill and the deduction of interest on intercompany loans for Dutch tax purposes. This goodwill and deductible interest is associated with our internal restructuring, and we are currently in discussions with the Dutch tax authorities concerning our ability to take advantage of the tax savings associated with it. See "Income Taxes Payable".

In connection with the draft tax audit report, we have had discussions with the Dutch tax authorities concerning our internal restructuring. In the course of such discussions, the Dutch tax authorities have confirmed to us that they will not seek to tax any capital gain that may be associated with the sale of the relevant economic interests in connection with our internal restructuring, but instead will focus their analysis only on the amount of goodwill and deductible interest related to our internal restructuring and the percentage of goodwill and deductible interest from our internal restructuring that should ultimately be attributed to our non-Dutch activities. The outcome of such discussions could limit our ability to take advantage of future tax savings associated with our internal restructuring by limiting the amount of goodwill that we may amortize and the amount of interest that we may deduct for tax purposes in future periods. However, based upon current facts and circumstances, applicable tax law, regulation and precedent, discussions with relevant tax authorities and professional advisers and other relevant criteria, we estimate that it is currently probable that we will realize benefits relating to at least U.S.$434.0 million of amortizable goodwill and at least U.S.$768.0 million of interest bearing intercompany debt in connection with our internal restructuring at January 1, 2000 and that such amounts will result in tax losses which may be carried forward for Dutch income tax purposes. Notwithstanding our current estimates, however, it is impracticable to quantify definitively at this time the effect that the outcome of such discussions may have on our actual tax position, because such definitive quantification depends on a number of possible future events, including the specific factual findings and legal and regulatory positions that may be taken by the Dutch tax authorities in any possible future challenge to our internal restructuring, as well as the outcome of any relevant proceedings. In addition, in December 2001, U.S.$379.5 million of the intercompany indebtedness of Bluewater Holding B.V. relating to the internal restructuring was

converted to share capital, thereby reducing the amount of tax benefits that we may take advantage of in subsequent periods. While we believe that it is probable that we will realize tax benefits in amounts that are not less than the foregoing estimates as set forth above and that it is unlikely that the outcome of these discussions or any proceedings relating thereto will have a material adverse effect on our financial position, there can be no assurance in this regard and we could lose some or all of the future anticipated tax savings associated with our internal restructuring.

We have recorded a deferred tax asset based on our estimate of the probable result of these discussions. The carrying value of our net deferred tax assets assumes a positive outcome of our discussions with the Dutch tax authorities and that we will be able to generate sufficient future taxable income in certain tax jurisdictions to take advantage of the benefits associated therewith. We believe that it is more likely than not that this deferred tax asset will be realized. However, if this assessment is incorrect, we may be required to record full or partial valuation allowances against our deferred tax assets resulting in the inclusion of additional income tax expense in our consolidated financial statements. We evaluate the realizability of the deferred tax assets and assess the need for a valuation allowance on a quarterly basis. We did not record a valuation allowance in the period ended June 30, 2003.

Tax Lease Benefits Liability

Our tax lease benefits liability relates to UK tax leasing transactions that we entered into from 1994 to 1999 with respect to the Uisge Gorm, the Glas Dowr and the topsides of Bleo Holm and a tax lease that we signed in April 2003 for the topsides of the Haewene Brim. These arrangements allow the lessor to claim tax depreciation in respect of its expenditure to acquire the vessel or the equipment, which is passed on to, or shared with, us in the form of reduced rentals. Our rental payment obligations were calculated by reference to a number of tax and financial assumptions made at the time the leases were entered into. Payment arrangements at the inception of the lease transactions were structured, and security has been provided, such that, subject to certain adjustments, we do not have any current rental payment obligations with respect to the Uisge Gorm, the Glas Dowr, the topsides of the Bleo Holm or the topsides of the Haewene Brim. Our tax lease benefits liability represents the amount that we would be required to pay the lessor in the event of a voluntary termination. In the event of an involuntary termination or an adverse tax change under our tax lease arrangements (whether prospective or retrospective), the tax lease benefits liability presented in our balance sheets may be required to be repaid to the lessor at an amount greater than the carrying value of the liability, which could have a material adverse effect on our financial condition and results of operations.

Tangible Fixed Assets and Depreciation

Our FPSOs account for approximately 75.0% of our total assets, are our primary sources of revenues and, accordingly, represent our most material fixed assets. We account for the value of these assets at their construction or acquisition cost and depreciate them on a straight-line basis over an estimated useful life of 15 years. An increase or decrease in the actual useful lives of our FPSOs over their estimated useful lives could result in significantly higher or lower annual depreciation expenses, which could have a material effect on our results of operations and shareholder's equity. In addition, our ability to recover the book value of our FPSOs depends, to a large extent, on our ability to enter into profitable service agreements for the vessels. If we are unable to secure profitable service agreements or if other circumstances arise indicating that the carrying amount an FPSO may not be recoverable, we may be required to record an impairment loss, which could similarly affect our results of operations and shareholder's equity. No circumstances arose in 2000, 2001, 2002 or in the period ended June 30, 2003 that indicated that our FPSOs could be impaired and, therefore, we did not record any impairment losses relating to our fleet.

Accounts Receivable

Accounts receivables are stated at face value less an allowance for possible uncollectable accounts. We continuously monitor collections and payments from our customers and maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issues that we have identified. Because our accounts receivables are concentrated in a relatively small number of customers, a significant change in the liquidity or financial position of these customers could have a material adverse effect on the collectability of our accounts receivables and our results of operations. In both the six months ended June 30, 2003 and the three months ended June 30, 2003, we recorded a release of the provision of U.S.$36,000.

Results of Operations

		For the six months ended June 30,						For the three months ended June 30,
		For the six months ended June 30,				Change 2002-2003		For the three months ended June 30,				Change 2002-2003
		2002		2003		Change 2002-2003		2002		2003		Change 2002-2003
		(in U.S.$ thousands)				(%)		(in U.S.$ thousands)				(%)
Revenues
FPSO business		103,570		133,192		28.6		53,870		82,437		53.0
SPM business		21,389		10,558		(50.6	)	15,027		5,213		(65.3	)

Total		124,959		143,750		15.0		68,897		87,650		27.2
Operating expenses
Operations expenses
	FPSO business	34,939		76,554		119.1		18,323		55,754		204.3
	SPM business	28,371		14,508		(48.9	)	17,823		5,894		(66.9	)

	Total	63,310		91,062		43.8		36,146		61,648		70.6
Selling, general and administrative expenses		5,232		5,514		5.4		2,690		3,083		14.6
Other operating income		(1,424	)	(2,016	)	41.6		(1,027	)	(1,023	)	(0.4	)

Depreciation of tangible fixed assets and amortization of intangible assets		27,736		25,925		(6.5	)	13,933		12,973		(6.9	)

Total operating expenses		94,854		120,485		27.0		51,742		76,681		48.2

Operating income
FPSO business		39,426		28,340		(28.1	)	21,205		12,255		(42.2	)
SPM business		(9,321	)	(5,075	)	(45.6	)	(4,050	)	(1,286	)	(68.2	)

	Total	30,105		23,265		(22.7	)	17,155		10,969		(36.1	)

Financial income and expense
Interest income		1,946		1,714		(11.9	)	996		886		11.0
Interest expense		(23,926	)	(22,962	)	(4.0	)	(13.634	)	(11,859	)	(13.0	)
Currency exchange results		(261	)	987		(478.2	)	229		2,404		949.8

	Total	(22,241	)	(20,261	)	(8.9	)	(12,409	)	(8,569	)	(30.9	)

Income before taxes		7,864		3,004		(61.8	)	4,746		2,400		(49.4	)
Income taxes		(11,374	)	(13,902	)	22.2		(5,193	)	(6,704	)	29.1

Net income		19,238		16,906		(12.1	)	9,939		9,104		(8.4	)

EBITDA⁽¹⁾
	FPSO business	66,550		53,968		(18.9	)	34,773		25,086		(27.9	)
	SPM business	(8,709	)	(4,778	)	(45.1	)	(3,685	)	(1,144	)	(69.0	)

	Total	57,841		49,190		(15.0	)	31,088		23,942		(23.0	)

Note:

(1): A reconciliation of EBITDA to net cash provided by operating activities is included under "Unaudited Other Financial Data and Ratios".

Six Months Ended June 30, 2003 Compared with Six Months Ended June 30, 2002

Revenues

Our revenues were U.S.$143.8 million during the six months ended June 30, 2003, up 15% from U.S.$125.0 million in the six months ended June 30, 2002. Revenues generated by our FPSO business amounted to U.S.$133.2 million in the six months ended June 30, 2003, up 28.6% from U.S.$103.6 million in the six months ended June 30, 2002, while revenues in our SPM business amounted to U.S.$10.6 million in the six months ended June 30, 2003, down 50.6% from U.S.$21.4 million in the six months ended June 30, 2002.

Revenues from our FPSO business increased U.S.$29.6 from the six months ended June 30, 2002 to the six months ended June 30, 2003 due to the recognition in the six months ended June 30, 2003 of U.S.$29.9 million of reimbursable expenses incurred in connection with the installation of subsea equipment on the Sable Field, compared to U.S.$0.1 million in the comparable period in 2002, and U.S.$4.0 million of reimbursable expenses incurred in connection with the installation of a new water injection facility on the Haewene Brim, compared to U.S.$1.7 million incurred in connection with the produced water treatment unit on the Uisge Gorm in the comparable period in 2002. This increase was in part offset by a reduction in tariff payments with respect to the Bleo Holm due to increased downtime in connection with maintenance of the gas pipework (U.S.$1.7 million) and the cessation in 2002 of oil bonus payments with respect to the Uisge Gorm (U.S.$0.8 million).

The decrease in the revenues of our SPM business was due to the lower level of our SPM activities during the six months ended June 30, 2003. Although we were awarded three SPM delivery contracts for the development of buoy mooring systems during the six months ended June 30, 2003, we do not expect payments under the contracts to have a material effect on our result of operations in the future.

Operations Expenses

Our operations expenses were U.S.$91.1 million in the six months ended June 30, 2003, up 43.8% from U.S.$63.3 million in the six months ended June 30, 2002. In our FPSO business, our operations expenses were U.S.$76.6 million in the six months ended June 30, 2003, compared to U.S.$34.9 million in the six months ended June 30, 2002. In our SPM business, operations expenses amounted to U.S.$14.5 million in the six months ended June 30, 2003, compared to U.S.$28.4 million in the six months ended June 30, 2002.

The increase of U.S.$41.7 million in the operations expenses of our FPSO business during the six months ended June 30, 2003 was attributable mainly to the recognition of U.S.$33.9 million in the six months ended June 30, 2003 of reimbursable expenses as described above under "Revenues" with respect to the Sable Field and the Haewene Brim, compared with U.S.$1.8 million in the comparable prior period. While we will be fully reimbursed for these expenses, under our accounting policies, we include the reimbursement in our revenues and account for the associated cost in our operations expenses. The increase was also attributable to a change that occurred between periods in the manner in which we allocate expenses between our FPSO and SPM business, resulting in a U.S.$7.1 million increase in expenses previously allocated to our SPM business (U.S.$2.7 million in general overhead expenses, U.S.$2.2 million in internal project expenses and U.S.$2.2 million in tender expenses). Further, operations expenses increased by U.S.$2.5 million attributable to one-time costs relating to maintenance on the Bleo Holm. The overall increase was in part offset by our claim for reimbursement of U.S.$2.6 million for costs relating to gas pipework on the Bleo Holm described above under "Revenues".

The operations expenses of our SPM business decreased U.S.$13.9 million during the six months ended June 30, 2003. U.S.$7.1 million of this decrease was due to the reallocation of certain expenses

to our FPSO business during the period, as described above, U.S.$3.5 million was due to the lower level of SPM activities and U.S.$3.3 million was due to the loss that we incurred in connection with the development of an SPM system during the six months ended June 30, 2003. The loss on the SPM system was attributable to the replacement of an installation subcontractor and costs related to the consequential delay.

Selling, General and Administrative Expenses

Our selling, general and administrative expenses amounted to U.S.$5.5 million during the six months ended June 30, 2003, compared to U.S.$5.2 million during the six months ended June 30, 2002. The increase in selling, general and administrative expenses was due to increased pension costs.

Depreciation of Tangible Fixed Assets

Our charges for depreciation of tangible fixed assets amounted to U.S.$25.9 million in the six months ended June 30, 2003, down 6.5% from U.S.$27.7 million in the six months ended June 30, 2002. The relative decrease in the amount of these charges resulted from the fact we did not record depreciation changes during the six months ended June 30, 2003 for the flowlines on the Uisge Gorm. This equipment was fully depreciated in July 2002.

Operating Expenses

Due to foregoing factors, our total operating expenses increased from U.S.$94.9 million in the six months ended June 30, 2002 to U.S.$120.5 million in the six months ended June 30, 2003.

Operating Income

Due to foregoing factors, our operating income amounted to U.S.$23.3 million in the six months ended June 30, 2003, compared to U.S.$30.1 million in the six months ended June 30, 2002, while our operating margin decreased to 16.2% of our revenues in the six months ended June 30, 2003, compared to 24.1% of our revenues in the six months ended June 30, 2002.

Financial Income and Expense

Our net financial expense amounted to U.S.$20.3 million in the six months ended June 30, 2003, compared to U.S.$22.2 million in the six months ended June 30, 2002.

Our interest expense in the six months ended June 30, 2003 decreased due to the capitalization of U.S.$4.9 million of interest, compared to no interest being capitalized in the comparable period in 2002. This decrease was offset by an increase in the amount of our outstanding indebtedness and an increase in the average weighted interest rate payable in respect thereof. The increase in our total debt resulted from the cost of modifying the Glas Dowr for its redeployment to the Sable Field, while the increase in our weighted average interest rate resulted from our issuance of an additional U.S.$75.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012 in April 2003. Although the proceeds from the issuance of the 10¹/4% Senior Notes due 2012 were used to repay indebtedness under our credit facility, their issuance at a relatively higher interest rate led to an increase in our weighted average interest rate during the six months ended June 30, 2003. Due to these factors, our total interest expense decreased from U.S.$23.9 million in the six months ended June 30, 2002 to U.S.$23.0 million in the six months ended June 30, 2003.

At the same time, our interest income decreased from U.S.$1.9 million in the six months ended June 30, 2002 to U.S.$1.7 million in the six months ended June 30, 2003 due to a decrease in the interest rate payable on our restricted cash deposits. Our currency exchange results increased from a loss of U.S.$261,000 in the six months ended June 2002 to a profit of U.S.$987,000 in the six months

ended June 30, 2003 as a result of favorable movements in the U.S. dollar to pounds sterling exchange rate.

Income before Taxes

Due to the foregoing factors, our income before taxes was U.S.$3.0 million in the six months ended June 30, 2003, down 61.8% from U.S.$7.9 million in the six months ended June 30, 2002. As a percentage of revenues, our income before taxes decreased from 6.3% in the six months ended June 30, 2002 to 2.1% in the six months ended June 30, 2003.

Income Taxes and Net Income

We recorded U.S.$13.9 million of income tax credits in the six months ended June 30, 2003, compared to U.S.$11.4 million of income tax credits in the six months ended June 30, 2002. These income tax credits consisted of current tax charges of U.S.$855,000 in the six months ended June 30, 2003, compared to current tax charges of U.S.$1.4 million in the six months ended June 30, 2002, and deferred tax credits of U.S.$14.8 million in the six months ended June 30, 2003, compared to deferred tax credits of U.S.$12.8 million in the six months ended June 30, 2002. The deferred tax credits primarily resulted from the increase of tax loss carry-forwards resulting from our internal restructuring. After taking account of our income tax credits, our net income amounted to U.S.$16.9 million in the six months ended June 30, 2003, down 12.1% from U.S.$19.2 million in the six months ended June 30, 2002.

Three Months Ended June 30, 2003 Compared with Three Months Ended June 30, 2002

Revenues

Our revenues were U.S.$87.7 million during the three months ended June 30, 2003, up 27.2% from U.S.$68.9 million in the three months ended June 30, 2002. Revenues generated by our FPSO business amounted to U.S.$82.4 million in the three months ended June 30, 2003, up 53.0% from U.S.$53.9 million in the three months ended June 30, 2002, while revenues in our SPM business amounted to U.S.$5.2 million in the three months ended June 30, 2003, down 65.3% from U.S.$15.0 million in the three months ended June 30, 2002.

Revenues from our FPSO business increased by U.S.$28.6 million from the three months ended June 30, 2002 to the three months ended June 30, 2003 due to the recognition in the three months ended June 30, 2003 of U.S.$29.7 million of reimbursable expenses incurred in connection with the installation of subsea equipment on the Sable Field, compared to none in the comparable period in 2002, and U.S.$3.0 million of reimbursable expenses incurred in connection with the installation of a new water injection facility on the Haewene Brim, compared to U.S.$1.2 million incurred in connection with the produced water treatment unit on the Uisge Gorm in the comparable period in 2002. This increase was in part offset by a reduction in tariff payments with respect to the Bleo Holm due to increased downtime in connection with maintenance of the gas pipework (U.S.$0.4 million), the cessation in 2002 of oil bonus payments with respect to the Uisge Gorm (U.S.$0.4 million) and a decrease in the price of oil compared to the prior period resulting in a decrease in revenues attributable to the Munin (U.S.$0.9 million).

The decrease in the revenues of our SPM business was due to the lower level of our SPM activities during the three months ended June 30, 2003. Although we were awarded two SPM delivery contracts for the development of buoy mooring systems during the three months ended June 30, 2003, we do not expect payments under the contracts to have a material effect on our result of operations in the future.

Operations Expenses

Our operations expenses were U.S.$61.6 million in the three months ended June 30, 2003, up 70.6% from U.S.$36.1 million in the three months ended June 30, 2002. Our operations expenses for our FPSO business were U.S.$55.8 million in the three months ended June 30, 2003, compared to U.S.$18.3 million in the three months ended June 30, 2002. Our operations expenses for our SPM business amounted to U.S.$5.9 million in the three months ended June 30, 2003, compared to U.S.$17.8 million in the three months ended June 30, 2002.

The increase of U.S.$37.4 million in the operations expenses of our FPSO business during the three months ended June 30, 2003 was attributable mainly to the recognition of U.S.$32.7 million in the three months ended June 30, 2003 of reimbursable expenses as described above under "Revenues" with respect to the Sable Field and the Haewene Brim, compared with U.S.$1.2 million in the comparable prior period. While we will be fully reimbursed for these expenses, under our accounting policies, we include the reimbursement in our revenues and account for the associated cost in our operations expenses. The increase was also attributable to a change that occurred between periods in the manner in which we allocate expenses between our FPSO and SPM business, resulting in a U.S.$4.1 million increase in expenses previously allocated to our SPM business (U.S.$0.9 million in general overhead expenses, U.S.$1.5 million in internal project expenses and U.S.$1.7 million in tender expenses). Further, operations expenses increased by U.S.$1.9 million attributable to one-time costs relating to maintenance on the Bleo Holm. This overall increase was in part offset by our claim for reimbursement of U.S.$1.2 million for costs relating to gas pipework on the Bleo Holm described above under "Revenues".

The decrease of U.S.$11.9 million in the operations expense of our SPM business during the three months ended June 30, 2003 was due to the reallocation of certain expenses to our FPSO business during the period, as described above and due to the lower level of SPM activities. Without giving effect of the reallocation and the lower level of activities, our SPM operations expenses would have actually increased due to a U.S.$1.4 million loss that we incurred in connection with the development of an SPM system during the three months ended June 30, 2003. The loss on the SPM system was attributable to the replacement of an installation subcontractor and costs related to the consequential delay.

Selling, General and Administrative Expenses

Our selling, general and administrative expenses amounted to U.S.$3.1 million during the three months ended June 30, 2003, compared to U.S.$2.7 million during the three months ended June 30, 2002. The increase in selling, general and administrative expenses was due to increased pension costs.

Depreciation of Tangible Fixed Assets

Our charges for depreciation of tangible fixed assets amounted to U.S.$13.0 million in the three months ended June 30, 2003, down 6.9% from U.S.$13.9 million in the three months ended June 30, 2002. The relative decrease in the amount of these charges resulted from the fact we did not record depreciation changes during the three months ended June 30, 2003 for the flowlines on the Uisge Gorm. This equipment was fully depreciated in July 2002.

Operating Expenses

Due to foregoing factors, our total operating expenses increased from U.S.$51.7 million in the three months ended June 30, 2002 to U.S.$76.7 million in the three months ended June 30, 2003.

Operating Income

Due to foregoing factors, our operating income amounted to U.S.$11.0 million in the three months ended June 30, 2003, compared to U.S.$17.2 million in the three months ended June 30, 2002, while our operating margin decreased to 12.5% of our revenues in the three months ended June 30, 2003, compared to 24.9% of our revenues in the three months ended June 30, 2002.

Financial Income and Expense

Our net financial expense amounted to U.S.$8.6 million in the three months ended June 30, 2003, compared to U.S.$12.4 million in the three months ended June 30, 2002.

Our interest expense in the three months ended June 30, 2003 decreased due to the capitalization of U.S.$2.7 million of interest, compared to no interest being capitalized in the comparable period in 2002. This decrease was offset by an increase in the amount of our outstanding indebtedness and an increase in the average weighted interest rate payable in respect thereof. The increase in our total debt resulted from the cost of modifying the Glas Dowr for its redeployment to the Sable Field, while the increase in our weighted average interest rate resulted from our issuance of an additional U.S.$75.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012 in April 2003. Although the proceeds from the issuance of the 10¹/4% Senior Notes due 2012 were used to repay indebtedness under our credit facility, their issuance at a relatively higher interest rate led to an increase in our weighted average interest rate during the three months ended June 30, 2003. Due to these factors, our total interest expense decreased from U.S.$13.6 million in the three months ended June 30, 2002 to U.S.$13.5 million in the three months ended June 30, 2003.

At the same time, our interest income decreased from U.S.$1.0 million in the three months ended June 30, 2002 to U.S.$0.9 million in the three months ended June 30, 2003 due to a decrease in the interest rate payable on our restricted cash deposits. Our currency exchange results increased from a profit of U.S.$229,000 in the three months ended June 30, 2002 to a profit of U.S.$2.4 million in the three months ended June 30, 2003 as a result of favorable movements in the U.S. dollar to pounds sterling exchange rate.

Income before Taxes

Due to the foregoing factors, our income before taxes was U.S.$2.4 million in the three months ended June, 30 2003, down 49.4% from U.S.$4.7 million in the three months ended June 30, 2002. As a percentage of revenues, our income before taxes decreased from 6.9% in the three months ended June 30, 2002 to 2.7% in the three months ended June 30, 2003.

Income Taxes and Net Income

We recorded U.S.$6.7 million of income tax credits in the three months ended June 30, 2003, compared to U.S.$5.2 million of income tax credits in the three months ended June 30, 2002. These income tax credits consisted of current tax charges of U.S.$384,000 in the three months ended June 30, 2003, compared to current tax charges of U.S.$814,000 in the three months ended June 30, 2002, and deferred tax credits of U.S.$7.1 million in the three months ended June 30, 2003, compared to deferred tax credits of U.S.$6.0 million in the three months ended June 30, 2002. The deferred tax credits primarily resulted from the increase of tax loss carry-forwards resulting from our internal restructuring. After taking account of our income tax credits, our net income amounted to U.S.$9.1 million in the three months ended June 30, 2003, down 8.4% from U.S.$9.9 million in the three months ended June 30, 2002.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash flows generated from our operations and external debt. Our primary uses of cash are to fund working capital, to service indebtedness and to fund investments in new FPSOs. We believe that our working capital is sufficient to satisfy current requirements.

Net Cash Provided by Operating Activities

Net cash provided by operating activities consists of operating income earned from our service agreements and our SPM delivery contracts, adjusted for investments in working capital and non-cash items such as depreciation and amortization. Working capital is defined as our current assets less our current liabilities. Net cash provided by operating activities was U.S.$52.1 million in the six months ended June 30, 2002 and U.S.$25.0 million in the six months ended June 30, 2003. The decrease in net cash provided by operating activities from the six months ended June 30, 2002 to the six months ended June 30, 2003 was due primarily to a U.S.$9.6 million investment in working capital, which was used in connection with the development of the three SPM systems and work performed at the Sable Field.

Net Cash (Used in) Investing Activities

Net cash (used in) investing activities depends primarily on the amount of capital expenditures that we make in connection with the construction, modification or acquisition of FPSOs. Net cash (used in) investing activities totaled U.S.$40.5 million in the six months ended June 30, 2002 and U.S.$55.3 million in the six months ended June 30, 2003. The relative increase in our net cash outflow from the six months ended June 30, 2002 to the six months ended June 30, 2003 resulted from a U.S.$55.4 million increase in expenses relating to the modification and redeployment of the Glas Dowr. The cost of these modifications has been capitalized and added to the historic cost of the vessel.

Net Cash Provided by Financing Activities

Net cash provided by financing activities is primarily driven by our borrowing activities. These cash flows amounted to U.S.$5.5 million in the six months ended June 30, 2002 and U.S.$20.5 million in the six months ended June 30, 2003. Our net indebtedness typically increases while we are modifying, developing or acquiring an FPSO, while our net indebtedness tends to decrease if we are not engaged in those activities. The increase in net cash provided by financing activities from the six months ended June 30, 2002 to the six months ended June 30, 2003 resulted from the unwinding of the interest rate swap and from the issuance of our additional U.S.$75.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012. We used our net gain from unwinding the swap and the proceeds from the additional offering of our 10¹/4% Senior Notes due 2012 to reduce indebtedness under our credit facility and to pay the costs and expenses of that offering.

Financing Arrangements and Contractual Obligations

As of June 30, 2003, we did not have any short-term bank debt under working capital facilities or our credit facility. We had total long-term bank debt of U.S.$264.6 million incurred under our credit facility and cash of U.S.$13.1 million. We also had U.S.$335.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012 outstanding and U.S.$130.2 million of indebtedness outstanding under the subordinated Marenco loan.

Credit Facility. Our credit facility is a U.S.$600.0 million revolving credit facility that we entered into in January 2002 with an international syndicate of banks. The facility has a tenor of eight years and may be used to finance the development of new FPSOs and for general corporate purposes. Its structure includes a borrowing base, calculated according to the present value of cash flows we earn or

expect to earn under our FPSO service agreements and a proportion of the residual value of our assets. The facility may be drawn upon at any time up to the lower of the current amount of the facility limit and the borrowing base. The facility limit, which was U.S.$520.0 million as of June 30, 2003, reduces by U.S.$20.0 million per quarter and is scheduled to reach zero in December 2009. Interest is payable at a rate that is equal to a margin over LIBOR. The margin, which is currently 1.400%, varies from 1.300% to 1.700% depending on certain factors. As of June 30, 2003, the applicable interest rate was 2.48%.

The following table presents certain information regarding the expected availability of funding under our credit facility in its current form during the periods indicated.

	Year ending December 31,
	2003	2004	2005	2006	2007	2008	2009
	(in U.S.$ millions)
Facility limit	480	400	320	240	160	80	0
Borrowing base⁽¹⁾	479	382	325	287	271	248	223

Note:

(1): Based on our current FPSO fleet.

Other Financing Arrangements. In addition to the credit facility described above, we also have entered into the following financing arrangements.

•: 10¹/4% Senior Notes due 2012. In February 2002, we issued U.S.$260.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012 through our finance subsidiary, Bluewater Finance Limited, at a price of 98.47% of the principal amount thereof. We used the gross proceeds from the issuance of the 10¹/4% Senior Notes due 2012 to repay approximately U.S.$248.5 million of indebtedness outstanding under our credit facility and to pay approximately U.S.$7.5 million of costs relating to the issuance. In April 2003, we issued an additional U.S.$75.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012 at a price of 100.5% of the principal amount thereof, plus accrued interest from and including February 15, 2003 to but excluding the issue date. We used approximately U.S.$75.4 million of the gross proceeds from the issuance, excluding the accrued interest from and including February 15, 2003 to but excluding the issue date, from the issuance to repay approximately U.S.$73.4 million of indebtedness outstanding under our credit facility and to pay U.S.$2.0 million of the costs relating to the issuance. The 10¹/4% Senior Notes due 2012, which currently have an aggregate principal amount of U.S.$335.0 million, have been fully and unconditionally guaranteed, on a joint and several basis, by our other group companies.
•: Subordinated Marenco Loan. We have borrowings outstanding under a loan from Marenco Investments Limited, our affiliate, that is fully subordinated to both our credit facility and the guarantees of our 10¹/4% Senior Notes due 2012. As of June 30, 2003, the total amount of this loan (including accrued interest) was U.S.$130.2 million. Interest is payable at a rate of 7.0% per annum; however, cash interest payments on the loan can be made only in accordance with the provisions of our credit facility and the restricted payment provisions of the indenture for our 10¹/4% Senior Notes due 2012. In the six months ended June 30, 2003 and in the three months ended June 30, 2003, we accrued approximately U.S.$4.4 million and U.S.$2.2 million, respectively, of interest on the loan.
•: Guarantee Facilities. We are party to a U.S.$10.0 million guarantee facility with Lloyds TSB, a U.S.$20.0 million performance guarantee facility with ING Bank and a U.S.$16.4 million performance guarantee facility with Nationale Borg. The facilities enable us to give bank guarantees to our suppliers. As of June 30, 2003, we had U.S.$5.1 million outstanding under our guarantee facilities.

Scheduled Maturities of Contractual Obligations. The following table presents the scheduled maturities of our contractual obligations, assuming that any available rollover provisions were inapplicable, as of June 30, 2003.

		Total	< year	1-3 years	3-5 years	> 5 years
		Payments due by Period (in U.S.$ thousands)
Long-term debt obligations		599,567	—	24,567	160,000	415,000
Operating lease obligations		6,138	2,130	3,343	665	—

	Total	605,705	2,130	27,910	160,665	415,000

Capital Expenditures

From time to time, we are required to make capital expenditures in respect of our FPSOs and our SPM development projects. Our current commitments for these expenditures, and the majority of our expected expenditures for 2003, relate to modifications that we have been required to make to the Glas Dowr's topsides and mooring system and work that we have been required to perform at the Sable Field to prepare the Glas Dowr for its redeployment to the location. See "Redeployment of the Glas Dowr".

Our future capital expenditures will depend primarily on the FPSO and SPM projects that we undertake. It is not possible to predict with certainty the extent of the capital expenditures that we will be required to make in connection with these projects. However, we believe that the amount will be primarily a function of the characteristics of the oil fields on which the FPSO or SPM system will be used, the requirements set forth in the applicable service agreement or SPM delivery contract and the design selected.

Research and Development

We have focused our research and development activities on technology that is integral to our FPSO and SPM businesses. We have an in-house design and engineering team consisting of engineers trained in a number of disciplines. We also access new sources of information or technology by entering into strategic alliances with equipment manufacturers, oil and gas companies, universities or by participating in joint industry programs. While the market for our products and services is subject to continual technological changes, development cycles from initial conception through introduction can extend over several years. Our efforts have resulted in the development of a number of inventions, new processes and techniques, many of which have been incorporated as improvements to our product lines. Our research and development activity has led to a number of patents or patent applications, principally in the area of SPM systems. During the six months ended June 30, 2003, our research and development expenditures were U.S.$200,000. During the three months ended June 30, 2003, our research and development expenditures were U.S.$100,000.

Quantitative and Qualitative Exposure to Market Risk

In the ordinary course of our business, we are exposed to a variety of market risks arising from fluctuations in interest rates and foreign currency exchange rates but generally are not exposed under our service agreements to any material risks relating to the price of oil. To manage the market risks to which we are exposed, we enter into market sensitive instruments based on internal policies and guidelines that are designed to mitigate our exposure to any adverse effects of changes in market conditions. We do not enter into market sensitive instruments for trading or speculative purposes. While we do not anticipate that the use of market sensitive instruments will have a material adverse effect on our consolidated financial position, results of operation or prospects, we cannot guarantee that our mitigation strategy will be effective.

Interest Rate Sensitivity

The majority of our indebtedness consists of advances under our credit facility and our outstanding 10¹/4% Senior Notes due 2012. We expect that in the future we will continue to have significant borrowings under our credit facility obligations under our 10¹/4% Senior Notes due 2012.

Advances under the credit facility bear interest at rates typically expressed as a margin over the appropriate interbank rate. In order to reduce our interest rate exposure, as of December 31, 2002 and as of June 30, 2003, we had swapped approximately 74.0% and 66.9%, respectively, of the outstanding indebtedness under our credit facility from floating rate to fixed rate.

Interest on our 10¹/4% Senior Notes due 2012 is payable at a rate of 10¹/4% per annum. To reduce the interest expense relating to our 10¹/4% Senior Notes due 2012, we entered into a fixed-to-floating interest rate swap transaction, with effect from April 25, 2003, that enabled us to swap the equivalent of the fixed rate amount of interest that is payable on U.S.$335.0 million aggregate principal amount of 10¹/4% Senior Notes due 2012 for the floating rate amount of interest that would be payable on an equal amount of indebtedness. On May 27, 2003, we cancelled the swap transaction. Under the swap, prior to the cancellation, we received interest payments that were calculated at a fixed rate of 10¹/4% and made interest payments that were calculated at a floating rate that was equal to a margin over LIBOR. We received U.S.$7.6 million on May 30, 2003, which represented our net gain from the cancellation of the swap transaction. We deferred this gain, which will be credited to the income statement over the remaining duration of the 10¹/4% Senior Notes due 2012, and used this payment to repay outstanding indebtedness under our credit facility. As of July 17, 2003 we re-entered into a fixed-to-floating interest rate swap transaction that enables us to swap the equivalents of the fixed rate amount of interest that is payable on U.S.$335.0 million aggregate principal amount of the 10¹/4% Senior Notes due 2012 for a floating rate amount of interest that would be payable on an equal amount of indebtedness. Under the swap, we will receive payments that are calculated at a fixed rate of 10¹/4% and make interest payments that are calculated at a floating rate that is equal to a margin of 6.11% over LIBOR.

The tables below provide information about our derivative financial instruments and other financial instruments that are sensitive to changes in interest rates, including interest rate swaps and debt obligations, that were outstanding as of December 31, 2002 and as of June 30, 2003. The June 30, 2003 data is provided because we significantly altered the profile of our interest rate sensitive instruments in connection with our issuance of an additional U.S.$75.0 million aggregate principal amount of our 10¹/4% Senior Notes due 2012 in April 2003 and our entry into, and subsequent cancellation of, the interest rate swap transaction described above. For debt obligations, the tables present our principal cash flows and related weighted average interest rates by expected maturity dates under our existing debt arrangements. For interest rate swaps, the tables present notional amounts and weighted average interest rates by expected (contractual) maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the swap. Weighted average variable rates are based on implied forward rates in the yield curve at the reporting date. The information is

presented in U.S. dollars, which is our reporting currency. The instrument's actual cash flows are also denominated in U.S. dollars.

		As of December 31, 2002
		Expected Maturity Date December 31,
		2003		2004		2005		2006		2007		Thereafter		Total	Fair Value
		(in thousands U.S.$ equivalents)
Liabilities
Long-Term Debt
Fixed rate debt (U.S.$)		—		—		—		—		—		125,849		125,849	160,612
	Average interest rate	7.0%		7.0%		7.0%		7.0%		7.0%		7.0%		—	—
Fixed rate debt (U.S.$)		—		—		—		—		—		—		—	260,000	⁽¹⁾
	Average interest rate	10.25%		10.25%		10.25%		10.25%		10.25%		10.25%		—	—
Variable rate debt (U.S.$)		—		—		4,733		80,000		80,000		160,000		324,733	—
	Average interest rate	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	—	—
Interest Rate Swaps
Variable to Fixed (U.S.$)		41,858		35,990		—		—		—		—		77,848	(4,273	)
	Average pay rate	6.7225%		6.7225%		—		—		—		—		—	—
	Average receive rate	LIBOR		LIBOR		—		—		—		—		—	—
Variable to Fixed (U.S.$)		73,481		36,821		35,092		7,006		—		—		152,400	(3,463	)
	Average pay rate	3.463%		3.463%		3.463%		3.463%		—		—		—	—
	Average receive rate	LIBOR		LIBOR		LIBOR		LIBOR		—		—		—	—

Notes:

(1): While indebtedness in respect of our notes amounted to U.S.$256.4 million as of December 31, 2002, the U.S.$260.0 million aggregate principal amount of the notes is payable upon maturity.
(2): Interest is payable at a rate that is equal to a margin over LIBOR. The margin varies from 1.300% to 1.700% depending on certain factors.

		As of June 30, 2003
		Expected Maturity Date June 30,
		2004		2005		2006		2007		2008		Thereafter		Total	Fair Value
		(in thousands U.S.$ equivalents)
Liabilities
Long-Term Debt
Fixed rate debt (U.S.$)		—		—		—		—		—		130,218		130,218	161,747
	Average interest rate	7.0%		7.0%		7.0%		7.0%		7.0%		7.0%		—	—
Fixed rate debt (U.S.$)		—		—		—		—		—		—		—	335,000	⁽¹⁾
	Average interest rate	10.25%		10.25%		10.25%		10.25%		10.25%		10.25%		—	—
Variable rate debt (U.S.$)		—		—		—		44,567		80,000		140,000		264,567	—
	Average interest rate	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	LIBOR+M	⁽²⁾	—	—
Interest Rate Swaps
Variable to Fixed (U.S.$)		31,537		25,845		—		—		—		—		57,382	(2,589	)
	Average pay rate	6.7225%		6.7225%		—		—		—		—		—	—
	Average receive rate	LIBOR		LIBOR		—		—		—		—		—	—
Variable to Fixed (U.S.$)		80,297		12,367		27,244		—		—		—		119,908	(2,951	)
	Average pay rate	3.463%		3.463%		3.463%		—		—		—		—	—
	Average receive rate	LIBOR		LIBOR		LIBOR		—		—		—		—	—

Notes:

(1): While indebtedness in respect of our notes amounted to U.S.$339.5 million as of June 30, 2003, the U.S.$335.0 million aggregate principal amount of the notes is payable upon maturity.
(2): Interest is payable at a rate that is equal to a margin over LIBOR. The margin varies from 1.300% to 1.700% depending on certain factors.

Exchange Rate Sensitivity

Our revenues are primarily denominated in U.S. dollars and, to a lesser extent, sterling. In the six months ended June 30, 2003 and in the three months ended June 30, 2003, approximately £11.8 million (U.S.$19.0 million) and £7.2 million (U.S.$11.6 million), respectively, of our revenues were denominated in sterling. Our expenses are denominated primarily in U.S. dollars and to a lesser degree, euro and sterling. We are exposed to fluctuations in foreign currency exchange rates, because a portion of our expenses and financial indebtedness is denominated in currencies that are different from our revenues. Our policy is to match, through our FPSO service agreements, the revenues in a

particular currency with our operating costs in that currency, thereby minimizing the risk associated with fluctuations in foreign currency exchange rates. We also match our indebtedness denominated in U.S. dollars with our revenues denominated in U.S. dollars. We purchase foreign currency exchange contracts from financial institutions to the extent of any residual exposure. We manage our outstanding currency exposure on a regular basis and net these exposures across our operations as a group. Gains and losses related to specific currency transactions are recognized as part of our income from financing activities.

We did not have any material forward currency exchange contracts as of December 31, 2002 or June 30, 2003; the total contract/notional amount and the value of our foreign currency exchange contracts are as follows:

		Expected Maturity Date
		As of June 30, 2003
		Total	Fair Value
		(in U.S.$ thousands)
Forward Exchange Agreements
(Receive €/Pay U.S.$)
	Aggregate Amount	24,756	24,525
(Receive £/Pay U.S.$)
	Aggregate Amount	24,087	29,849

These foreign currency exchange contracts mature on various dates through fiscal year 2003.

SIGNATURES

Pursuant to the requirements of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		AURELIA ENERGY N.V. (Registrant)
	By:	/s/ G.E. ELIAS (Signature) INTERTRUST (CURACAO) N.V. MANAGING DIRECTOR BY: G.E. ELIAS MANAGING DIRECTOR-CHAIRMAN
Date: August 28, 2003

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TABLE OF CONTENTS
CERTAIN DEFINITIONS
FORWARD-LOOKING STATEMENTS
UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AURELIA ENERGY N.V. UNAUDITED INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS
AURELIA ENERGY N.V. UNAUDITED INTERIM CONDENSED CONSOLIDATED BALANCE SHEETS
AURELIA ENERGY N.V. UNAUDITED INTERIM CONDENSED CONSOLIDATED STATEMENTS OF INCOME
AURELIA ENERGY N.V. UNAUDITED INTERIM CONDENSED CONSOLIDATED CASH FLOW STATEMENT
AURELIA ENERGY N.V. NOTES TO UNAUDITED INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS FOR THE SIX MONTHS AND THREE MONTHS ENDED JUNE 30, 2003 AND 2002
UNAUDITED OTHER FINANCIAL DATA AND RATIOS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SIGNATURES

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