As filed with the Securities and Exchange Commission on September 12, 2005

Registration No. 333-          

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Innovene Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	2860	20-3181950
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification No.)

Innovene Inc.

200 E. Randolph Street

Chicago, IL 60601

(312) 873-8700

(Address, Including Zip Code, and Telephone Number,

Including Area Code, of Registrant’s Principal Executive Offices)

The Corporation Trust Company

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

(Name, Address Including Zip Code, and Telephone Number,

Including Area Code, of Agent For Service)

Copies to:

Henry Kleeman
Senior Vice President and General Counsel
Innovene Inc.
200 E. Randolph Street
Chicago, IL 60601
(312) 873-8789 Kathryn A. Campbell
Sullivan & Cromwell LLP
1 New Fetter Lane
London EC4A 1AN
England
+44 (0) 207 959-8900 John W. Banes
Davis Polk & Wardwell
450 Lexington Avenue
New York, NY 10017
(212) 450-4000

        Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

         If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    o

         If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

         If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

         If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

         If delivery of the prospectus is expected to be made pursuant to Rule 434, check the following box.    o

CALCULATION OF REGISTRATION FEE

Title of each Class of Securities to be Registered	Proposed Maximum Offering Price(1)	Amount of Registration Fee
Common Stock, par value $0.01 per share	$1,000,000,000	$117,700

(1)  Estimated solely for the purpose of calculating the amount of the registration fee in accordance with Rule 457(o) under the Securities Act of 1933. Includes shares which the underwriters have the option to purchase from BP solely to cover over-allotments.

         The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to such Section 8(a), may determine.

The information in this prospectus is incomplete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION. DATED                     , 2005

Shares

Innovene Inc.

COMMON STOCK

        This is an initial public offering of shares of common stock of Innovene Inc. (Innovene). All of the shares of common stock are being sold by BP p.l.c. (BP), and we will not receive any of the net proceeds from the sale of these shares. Following the offering, BP will own approximately           % of our common stock, assuming no exercise of the over-allotment option.

      This is our initial public offering and no public market has existed for our shares prior to the offering. We anticipate that the initial public offering price will be between $          and $           per share.

      We intend to list our common stock on the New York Stock Exchange, Inc., or the NYSE, under the trading symbol “INV.”

      Investing in our common stock involves risks. See “Risk Factors” starting on page 9.

	Per share	Total
Initial public offering price
Underwriting discounts and commissions
Proceeds to BP

      BP has granted the underwriters the right to purchase up to an additional                      shares of common stock to cover over-allotments.

      The Securities and Exchange Commission (SEC) and state securities regulators have not approved or disapproved of the shares of our common stock or determined that this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

      The underwriters expect to deliver the shares to purchasers on                     , 2005.

Goldman, Sachs & Co. Morgan Stanley

Lehman Brothers UBS Investment Bank

Prospectus dated                    , 2005

[This page intentionally has been left blank.]

Table of Contents

Prospectus Summary	1
Risk Factors	9
Special Note Regarding Forward-Looking Statements and Market Data	19
Dividend Policy	20
Capitalization	21
Selected Combined Financial Data	22
Unaudited Pro Forma Combined Financial Data	25
Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Industry Overview	60
Business	68
Management	99
Principal Shareholder	112
Certain Relationships and Related Transactions	113
Description of Capital Stock	123
Shares Eligible for Future Sale	125
Certain U.S. Federal Tax Considerations for Non-U.S. Holders	126
Underwriting	129
Validity of the Shares	132
Experts	132
Where You Can Find More Information	132
Glossary	133
Index to Combined Financial Statements	F-1
EX-2.1
EX-23.1: CONSENT OF ERNST & YOUNG LLP

      You should rely only on the information contained in this prospectus. Neither we nor our subsidiaries have authorized anyone to provide you with information different from that contained in this prospectus. The prospectus may only be used for the purposes for which it has been published and no person has been authorized to give any information not contained in this prospectus. If you receive any other information, you should not rely on it. No offer of the shares of our common stock is made in any state where such an offer is not permitted.

      Until                     , 2005 (25 days after the date of this prospectus), all dealers that buy, sell or trade our stock, whether or not participating in the offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

PROSPECTUS SUMMARY

      This summary highlights information contained elsewhere in this prospectus. The information set forth below does not contain all the information you should consider before deciding to invest in our shares. We urge you to read the entire prospectus carefully, including the section “Risk Factors” and our combined financial statements, including the notes thereto.

      In this prospectus, “Innovene Inc.,” the “company,” “we,” “us” and “our” each refer to Innovene Inc. and its subsidiaries, including its predecessor businesses, which comprise certain assets, liabilities and associated infrastructure that were formerly part of BP’s Petrochemicals, Refining and Marketing, and Gas, Power and Renewables segments, as described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Basis of Presentation,” except where the context makes clear that the reference is only to Innovene Inc. itself and not to its subsidiaries or predecessor businesses. The assets and liabilities comprising the operations of our predecessor businesses will be transferred to us prior to the completion of the offering. A glossary of petrochemical and refining abbreviations used in this prospectus is set forth on page 133.

Our Company

      We are among the world’s largest petrochemical companies, with revenues of $17.9 billion in 2004. We conduct our business through petrochemical manufacturing sites in eight countries as well as two refineries which are fully integrated with our petrochemical facilities. At June 30, 2005, our total petrochemical production capacity was approximately 40 billion pounds per year and our refineries had a combined crude oil distillation capacity of approximately 400 thousand barrels per day (mbd). Our business is structured around five major sites, which account for approximately 70% of our petrochemical production volumes and approximately 85% of our overall production volumes.

      We have a global reach and leading market positions with respect to our key petrochemical products, which enable us to manage our business on a worldwide basis. We benefit from the cost advantages of operating large-scale petrochemical facilities and the high degree of integration at our major sites. We have an expanding position in the fast-growing Asian markets, which we serve through our operations in North America and Europe. We have an established regional office in Shanghai, China to manage our operations in Asia. Our competitive position in the petrochemical industry is supported by a portfolio of proprietary process technologies. Our two European refineries have the scale, location, product slate, feedstock flexibility and clean fuels capabilities necessary to be competitive in their respective markets and provide an earnings stream that is not driven by the same cyclical patterns as our petrochemical businesses. Our safety performance track record is among the best in the industry.

      Our business comprises certain assets, liabilities and associated infrastructure that were formerly part of BP’s Petrochemicals, Refining and Marketing, and Gas, Power and Renewables segments. We believe our separation from BP has created new opportunities for us. Historically, our business was a small part of a much larger organization and our performance lagged behind that of other companies in the petrochemicals sector. As a separate entity with our own management structure, we will be able to focus on the factors that are critical to the success of our petrochemical and refining businesses and benchmark ourselves directly against the performance of our competitors. Our benchmarking work has identified significant opportunities to improve the performance and optimize the use of our existing assets and to increase our margins. We intend to pursue growth opportunities by investing in new assets and forming joint ventures in regions that have access to low-cost feedstocks.

      We report our business on the basis of five segments, Olefins and Polymers (O&P) North America, O&P Europe, Global Derivatives, Refining, and Corporate and Other. The following chart provides an overview of our

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two principal businesses, the segments which each business comprises and the products we make in each of these segments:

(1)	Intersegmental sales amounted to $1,909 million for the year ended December 31, 2004.
(2)	For more information on how we calculate adjusted EBITDA, see “Selected Combined Financial Data — Use of Non-GAAP Financial Measures.”

     In our petrochemical business, we make olefins and related products, a broad range of polymers and various other petrochemical products directly or indirectly derived from olefins. We are among the largest volume manufacturers of olefins, polymers, and derivatives in the world. The focus of our olefins business is on ethylene and propylene, which are the two largest volume olefins and are key building blocks for polymers and derivatives. The olefins we make are primarily used as feedstock for our polymers and derivatives businesses. In addition, we sell olefins to third party customers for a variety of industrial and consumer applications, including plastics, rubber and fiber. In our polymers business, we focus on polyethylene and polypropylene. The largest volume product of our global derivatives business is acrylonitrile.

      The following table provides an overview of our capacity, global market position and certain regional market positions with respect to our key petrochemical products:

	Full-year
	capacity(1)		Global
	as of June		market		Selected regional
Key products	30, 2005		position(2)		market positions(2)
	(mmlbs)
Ethylene		8,860		#7		#4 in Europe
Polypropylene		5,680		#3		#2 in North America
HDPE		4,780		#3		#2 in Europe
						#4 in North America
Propylene		3,830		#9		#4 in Europe
Acrylonitrile		2,010		#1		#1 in Europe
						#1 in North America
Other		15,200
Total		40,360

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(1)	Capacity is defined as nameplate capacity. See “Business — Manufacturing — Overview” for more information on how we calculate capacity.
(2)	According to Chemical Markets Associates, Inc. (CMAI) data as of July 2005.

     In our refining business, we operate two large refineries in Europe. Our principal refining products are transport fuels, particularly diesel fuel and gasoline, naphtha, and heating and fuel oils. Our refineries are physically integrated with petrochemical plants located at the same sites. We have recently implemented a single management structure at these sites to further leverage the benefits of integration. The majority of the naphtha output of our refineries is used as inputs by the petrochemical plants located at the relevant sites. We have entered into agreements with BP, pursuant to which BP has agreed to buy the balance of our refinery products and to either market these products to its local customers or trade them on the commodity markets on our behalf.

      We have approximately 8,000 employees.

Competitive Strengths

•  Global Reach and Leading Market Positions. We are among the world’s largest petrochemical companies with 24 manufacturing sites in eight countries in North America and Europe, and a total petrochemical production capacity of approximately 40 billion pounds per year. From these sites, we serve approximately 2,700 customers who are located in the principal industrial regions of the world and use our products across a broad range of end-use applications, which we believe has allowed us to achieve and hold leading market positions with respect to each of our key products. According to CMAI, as measured by expected average annual capacity for 2005, we are among the top three companies globally for each of HDPE, polypropylene and acrylonitrile.

•  Vertically Integrated, Large Scale Producer. We have five large-scale sites, accounting for 85% of our total production volumes. All of these large-scale sites are integrated with major crackers and polymers and derivatives units, giving us the ability to capture margins across the value chain. Two of them are also integrated with onsite refineries, which differentiates us from many of our competitors. We believe that the scale of our global operations provides benefits by reducing our selling, administrative, and research and development costs on a per unit basis.

•  Strong Refining Platform. We own and operate two refineries focused on serving their respective markets with the product slate, feedstock flexibility and clean fuels capabilities necessary to be competitive. Each of our Grangemouth, United Kingdom and Lavéra, France refineries has a crude oil distillation capacity exceeding 200 mbd, which is larger than the average refinery size of each of our top five European refining competitors. Each of our refineries is equipped with a hydrocracker (HC) and a fluid catalytic cracker (FCC), which provides them with significant flexibility in processing heavy, sour crude oils into light, sweet middle distillates.

•  Extensive Portfolio of Leading Proprietary Technologies. Our technologies are positioned around our key products, including our gas phase polyethylene, gas phase polypropylene, slurry HDPE and acrylonitrile technologies. We believe that our technology is recognized as being among the lowest-cost in the petrochemical industry. As a result of their low cost, our technologies are widely used in the industry.

•  Experienced Management Team. We have a talented and experienced management team recruited from both within BP and externally. Our management team is led by Ralph Alexander, our Chief Executive Officer, who has worked in a variety of roles within BP, including as Chief Executive Officer of BP’s Gas, Power, and Renewables segment and as Chief Executive Officer of BP’s Petrochemicals segment. Mr. Alexander is supported by a team of business and functional leaders, including Mark Tomkins, our Chief Financial Officer, who have extensive experience in petrochemicals, refining, supply and trading and who we believe have the requisite skill set to successfully execute our strategy.

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Strategy

      We believe we have an opportunity to significantly improve our competitive position and future financial performance by implementing the key components of our strategy, which are to:

•  Achieve Performance Improvements Through Our Accelerator Program and By Implementing a Simplified Organizational Structure. To reduce our operating costs and maximize our operating efficiency, we have embarked on a comprehensive performance improvement program, which we refer to as our Accelerator program. Projects include eliminating unprofitable product lines, redesigning and enhancing our sales and marketing activities through optimized channels of trade, reducing our overhead and functional costs commensurate with our status as a standalone petrochemical company and making targeted investments to maximize our asset utilization and productivity. Throughout our organization, we have also reduced management and other organizational layers, focusing the business around three operating companies which are responsible for driving the performance of our overall business.

•  Maximize Cash Flow. We have revamped our incentive compensation programs for 2005 to focus every employee on a single financial goal, improving our adjusted EBITDA. In 2006, our incentive compensation programs will focus on three measures, adjusted EBITDA, capital expenditures and working capital, to further enhance the focus in our organization on delivering sustainable cash flow. We intend to use our free cash flow to reduce indebtedness and selectively expand our businesses, particularly to access low-cost feedstocks and serve growth markets.

•  Enhance the Value of Our Portfolio. We intend to focus on businesses that we believe have the potential to maintain or achieve cost and market leadership positions. We plan to manage our assets and businesses to achieve strong unit cost and gross margin performance relative to competitive benchmarks and make a meaningful financial contribution to our company. We expect that as a result of our Accelerator Program, the substantial majority of our assets and businesses will meet these benchmarks by 2007.

•  Expand Position in Locations with Low Cost Feedstocks. We intend to improve our long-term competitiveness by accessing low-cost feedstocks in the Middle East and north Africa through strategic collaborations with local partners and governments to build petrochemical complexes in these regions. In June 2005, we entered into a non-binding memorandum of understanding to construct a world-scale cracker and associated derivative complex in Saudi Arabia. Our goal is to sign a binding agreement and secure a guaranteed feedstock supply for the facility by year-end 2005 and commission the facility by 2009.

•  Maximize Profitability by Optimizing Supply and Trading Flows. We intend to continue to strengthen our supply and trading capabilities to ensure we derive maximum benefit from optimizing our operations, channels to market and market positions. The capabilities we have developed closely mirror the commercial model which BP has established and successfully operated in the oil and gas markets for many years. We believe this model distinguishes us from our peers in the petrochemical industry.

Our Relationship with BP

      In connection with our formation as a separate legal entity within the BP group, BP has transferred to us certain assets, liabilities and associated infrastructure relating to the former olefins and derivatives business of its Petrochemicals segment (not including joint ventures operating petrochemical facilities in China, Malaysia and Germany), refineries in Grangemouth, United Kingdom and Lavéra, France, which formed part of its Refining and Marketing segment, and a gas fractionator near Hobbs, New Mexico, which formed part of its Gas, Power and Renewables segment, in each case together with associated infrastructure.

      In connection with our separation from BP, BP has agreed to provide various administrative and operational support services to us. In addition, we have entered into a range of commercial arrangements with BP for the supply of refining and petrochemical feedstocks, the purchase and sale of refined products, the sharing of common infrastructure and the provision of utilities at various sites which we share with BP.

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Company Information

      We were incorporated in Delaware as a corporation on July 14, 2005 as a wholly-owned subsidiary of BP. Our principal executive offices are located at 200 E. Randolph Street, Chicago, IL 60601, and our telephone number is (312) 873-8700. Our website is at http://www.innovene.com. The information and other content contained on our website are not part of this prospectus.

The Offering

Issuer	Innovene Inc.
Common stock offered	shares
Common stock to be outstanding immediately after the offering	shares
Common stock to be held by BP immediately after the offering	shares
Over-allotment option	shares of common stock
Dividend policy	Upon completion of the offering, our Board of Directors intends to adopt a policy of declaring, subject to legally available funds, a quarterly cash dividend on each share of common stock at an annual rate initially equal to approximately      % of the initial public offering price, commencing with the first quarter of 2006. However, there can be no assurance that sufficient cash will be available to pay any such dividends. In addition, our dividend policy remains within the sole discretion of our Board of Directors and is subject to change. See “Dividend Policy” for a discussion of factors that will affect the determination by our Board of Directors to declare dividends, as well as other matters concerning our dividend policy.
Use of proceeds	We will not receive any of the net proceeds from the sale of any of the                     shares of common stock sold by BP in the offering.
Risk factors	See “Risk Factors” and other information included in this prospectus for a discussion of factors you should carefully consider before deciding to invest in our shares.
Proposed NYSE symbol	“INV”

      Unless otherwise indicated, all information in this prospectus:

•  assumes the over-allotment option has not been exercised; and

•  excludes restricted shares, restricted stock units and shares of common stock issuable upon the exercise of stock options granted to our executive officers and certain key employees in connection with the Innovene “BP LTPP” Conversion Plan (the Conversion Plan), the Innovene Incentive Plan 2005 (the Incentive Plan) and the Innovene Executive Share Matching Plan (the Executive Share Matching Plan).

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Summary Historical and Pro Forma Combined Financial Data

      The following table presents our summary combined financial data. The summary combined statements of operations data for the years ended December 31, 2002, 2003 and 2004, the summary combined statements of cash flows data for the years ended December 31, 2002, 2003 and 2004 and the summary combined balance sheet data as of December 31, 2003 and 2004 have been derived from our audited combined financial statements included elsewhere in this prospectus. The unaudited summary combined statements of operations data for the six months ended June 30, 2004 and 2005, the unaudited summary combined statements of cash flows data for the six months ended June 30, 2004 and 2005 and the unaudited summary combined balance sheet data as of June 30, 2005 have been derived from our unaudited accounting records for those periods and as of those dates. The unaudited summary combined financial data have been prepared on a basis consistent with the basis on which our audited combined financial statements have been prepared and, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of such data.

      We have derived the unaudited summary pro forma combined financial data from our audited combined financial statements for the year ended December 31, 2004 and our unaudited combined financial statements for the six months ended June 30, 2005 included elsewhere in this prospectus.

      The summary historical and pro forma combined financial data should be read in conjunction with “Selected Combined Financial Data,” “Unaudited Pro Forma Combined Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the combined financial statements and the accompanying notes included elsewhere in this prospectus.

      The unaudited summary pro forma combined statement of operations data reflect the combined operations of our company and our subsidiaries as if our separation from BP and the related transactions described below had occurred as of January 1, 2004. The unaudited summary pro forma combined balance sheet data reflects the combined operations of our company and our subsidiaries as if our separation from BP and the related transactions described below had occurred as of June 30, 2005. However, the unaudited summary pro forma combined financial data do not necessarily reflect what our financial position and results of operations actually would have been had our separation from BP and the related transactions described below occurred on the dates indicated nor do they purport to project our future financial performance.

      The unaudited summary pro forma combined financial data give pro forma effect to:

•  the recapitalization of our company prior to the offering, as part of which our share capital will be increased to           shares of common stock, par value $0.01 per share;

•  our repayment on March 22, 2005 of loans in the amount of $1,755 million which were secured by the petrochemical assets of our site in Grangemouth, United Kingdom, and the replacement of this debt by a loan from BP to us in the amount of $1,700 million, which was granted to us effective April 1, 2005;

•  the transfer from BP to us of the road and rail terminals of our Grangemouth site, which are not included in our historical combined financial statements; the relevant assets will be transferred to us prior to the offering, effective April 1, 2005;

•  the transfer from us to BP of our proportionate share of the shared power station of the Grangemouth site and certain infrastructure shared between us and BP at our site in Geel, Belgium; our historical combined financial statements show our proportionate share of these assets; the relevant assets were transferred from us to BP prior to the offering, effective April 1, 2005;

•  the transfer from us to BP of our obligations under certain pension and other post-employment benefit plans relating to former employees to reflect the fact that BP has agreed to retain these obligations;

•  the commercial arrangements entered into between us and BP effective January 1, 2005; and

•  insurance costs we expect to incur as a result of operating as a standalone company.

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														As of and for the six months
		As of and for the year ended December 31,												ended June 30,
											2004									2005
		2002			2003			2004			pro forma			2004			2005			pro forma
		($ in millions)
Combined Statements of Operations Data
Revenues			11,776			13,422			17,937			17,935			7,791			11,131			11,131
Cost of sales			(10,775	)		(12,586	)		(16,765	)		(16,768	)		(7,253	)		(9,876	)		(9,874	)
	Gross margin		1,001			836			1,172			1,167			538			1,255			1,257
Selling, general and administrative expenses			(734	)		(616	)		(630	)		(680	)		(341	)		(341	)		(341	)
Research and development expenses			(120	)		(115	)		(137	)		(137	)		(64	)		(51	)		(51	)
Restructuring and asset impairment charges			(93	)		(72	)		(345	)		(345	)		(5	)		(21	)		(21	)
	Operating profit		54			33			60			5			128			842			844
Equity (loss) income from investments in affiliates			(2	)		9			8			8			5			4			4
Interest expense			(35	)		(44	)		(49	)		(46	)		(25	)		(25	)		(26	)
Other income (expense), net			(65	)		(123	)		(24	)		(49	)		27			(42	)		(45	)
Income (loss) from continuing operations before income taxes			(48	)		(125	)		(5	)		(82	)		135			779			777
Provision for income taxes for continuing operations			(118	)		(90	)		(128	)		(99	)		(86	)		(233	)		(232	)
Net income (loss) from continuing operations			(166	)		(215	)		(133	)		(181	)		49			546			545
Loss from discontinued operations, net of income tax expense (benefit) of $0, $0, $(52) million, $0 and $0			(29	)		(25	)		(128	)					(11	)		(3	)
Net (loss) income			(195	)		(240	)		(261	)		(181	)		38			543			545
Net (loss) income per share(1)
	Basic
	Diluted
Average number of shares used in computing net (loss) income per share
	Basic
	Diluted

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											As of and for the six months
	As of and for the year ended December 31,										ended June 30,
										2004							2005
	2002			2003			2004			pro forma	2004			2005			pro forma
	($ in millions)
Combined Statements of Cash Flows Data
Net cash provided by operating activities of continuing operations		177			695			383				513			764
Net cash used in investing activities of continuing operations		(579	)		(561	)		(565	)			(218	)		(250	)
Net cash provided by (used in) financing activities of continuing operations		422			(140	)		203				(260	)		(559	)
Combined Balance Sheet Data
Current assets					3,520			4,398							5,129			5,129
Property, plant and equipment, net					7,050			7,136							6,737			6,737
Total assets		10,107			11,456			12,214							12,463			12,463
Current liabilities					2,085			2,210							4,508			4,465
Long-term debt		1,423			1,585			1,729							—			—
Total liabilities					4,937			5,201							5,172			5,129
Minority interest					1,242			—							—			—
Parent net investment					4,095			5,548							6,174			6,217
Accumulated other comprehensive income, net of tax					1,182			1,465							1,117			1,117
Supplemental Information
Adjusted EBITDA from continuing operations (2)		442			472			869				404			1,088

(1)

The computation of net (loss) income per share is based on the anticipated number of shares of our common stock outstanding upon completion of the offering. Prior to completion of the offering, there will be no outstanding options to purchase shares of our common stock or other potentially dilutive securities. In connection with the offering, our executive officers and certain key employees will be granted restricted shares, restricted stock units and stock options.

(2)

See “Selected Combined Financial Data — Use of Non-GAAP Financial Measures” for a definition of adjusted EBITDA and the reasons why management believes that the presentation of adjusted EBITDA provides useful information to investors. Set forth below is a reconciliation of net (loss) income to adjusted EBITDA for each period indicated:

										For the
										six months
	For the year ended									ended
	December 31									June 30,
	2002			2003			2004			2004		2005
	($ in millions)
Net (loss) income		(195	)		(240	)		(261	)		38		543
Loss from discontinued operations, net of tax		29			25			128			11		3
Interest expense		35			44			49			25		25
Provision for income taxes for continuing operations		118			90			128			86		233
Depreciation and amortization from continuing operations		423			517			545			244		284
Asset impairments from continuing operations		32			36			280			—		—
Adjusted EBITDA from continuing operations		442			472			869			404		1,088

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RISK FACTORS

      You should carefully consider the risks described below and all other information contained in this prospectus before deciding to purchase shares of our common stock. If any of these risks occur, our business, results of operations and financial condition could be adversely affected, and you could lose part or all of your investment.

Risks Related to Our Business

Our results are driven by industry margins, which are volatile and in the petrochemical industry historically have been highly cyclical. If industry margins decline from their current levels, our results and, potentially, our liquidity could be materially adversely affected.

      Our results are largely dependent on industry margins, which are a function of the relationship between supply and demand in the petrochemical and refining industries. Industry margins typically increase when demand approaches or exceeds available supply.

      The relationship between supply and demand in the petrochemical industry historically has been highly cyclical. This is primarily because product supply is driven by alternating periods of substantial capacity additions and periods in which no or limited capacity is added. As a general matter, companies are more likely to add capacity in periods when current or expected future demand is strong and margins are, or are expected to be, high. Investments in new capacity can result, and in the past frequently have resulted, in overcapacity, which typically leads to a reduction of margins. In response, companies typically reduce capacity or limit further capacity additions, eventually causing the market to be relatively undersupplied. The bottom of the last cycle was reached in 2001 and continued through 2003 due to weak demand and substantial simultaneous capacity additions. Since the beginning of 2004, profit margins have improved. However, the duration of the current upturn is difficult to predict and depends on a number of factors, including the extent of growth in key regions and the amount of capacity that will be built over the coming years. In the current environment, China is the principal driver of demand growth for petrochemical products. Any slowdown in Chinese growth for whatever reason could have a disproportionately negative effect on industry margins.

      Historically, industry margins in the petrochemical and refining industries have also been volatile due to a number of factors, most of which are beyond our control. These factors include:

•  short-term utilization rate fluctuations due to planned and unplanned plant outages;

•  political and economic conditions, which drive rapid changes in prices for our key feedstocks, namely the price of crude oil, gas and naphtha;

•  customers’ inventory management policies; and

•  exchange rate fluctuations.

      If industry margins decline, our results would be materially adversely affected and we could incur losses, particularly if industry margins in the petrochemical industry were to return to their 2001 levels or decline more significantly than they have in the past. Furthermore, increased volatility in industry margins could have a significant impact on our short-term results. In both cases, we would have to absorb any losses through our balance sheet or by borrowing additional funds. If we experience significant margin volatility or if we generate losses over a prolonged period and are unable to obtain additional funds, our liquidity could be materially adversely affected.

In recent years, our performance has lagged behind that of our competitors. There can be no assurance that we will be able to fully implement our ongoing performance improvement program or that it will yield the benefits we expect.

      In recent years, our performance has lagged behind that of other companies in the petrochemical industry, and we have recorded losses in each of the last three years. To improve our operating results, we have started a program aimed at enhancing our performance, which we call our Accelerator program. However, there can be no

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assurance that we will be able to successfully implement this program or that it will yield the benefits we expect or any benefits at all. If we are unable to improve our performance, our results may continue to lag behind those of our competitors.

Our feedstock costs are closely linked to oil and gas prices. If we are unable to pass on increases in our feedstock costs to our customers in the form of higher prices for our products, our margins would be materially adversely affected.

      Our margins are largely a function of the relationship between the prices that we are able to charge for our products and the costs of the feedstocks we require to make these products, which are principally driven by the price of oil and natural gas. Oil and gas prices have increased significantly in recent years. As a result of the recent tightening in the balance between the supply and demand for our products, we have been able to pass on these increases to our customers, although we typically experience some lag time due to the repricing intervals of our contracts with suppliers and customers and our customers’ inventory management policies, particularly in our petrochemical business. For example, our olefins contracts in Europe reprice quarterly, whereas the corresponding feedstock contracts typically reprice daily. However, there can be no assurance that we will always be able to pass on increases in oil and gas prices to our customers. If we are unable to pass through feedstock cost increases to our customers in the form of higher prices for our products, our margins, results of operations and financial condition would be materially adversely affected.

If the U.S. dollar weakens relative to other major currencies, our results could be materially adversely affected.

      A large proportion of our manufacturing costs and our selling, general and administrative expenses are incurred in currencies other than the U.S. dollar, principally the euro and the British pound, reflecting the location of our sites and corporate and business support centers. At the same time, although many of our sales are invoiced in local currencies, a substantial proportion of our revenues are denominated in or linked to the U.S. dollar. Therefore, our results in any given period are materially affected by fluctuations in the value of the U.S. dollar relative to the euro and the British pound. Despite its recent recovery, the decline in the value of the U.S. dollar relative to the euro and the British pound that started in 2002 has adversely affected our results. If the value of the U.S. dollar declines, our results of operations and financial condition could be materially adversely affected.

In Europe, and to a lesser extent North America, we face increasing pressures due to intense competition from companies with facilities in the Middle East. In addition, our customers could experience a loss of business to low-cost Asian competitors.

      The petrochemical industry in Europe, where the majority of our assets are concentrated, and, to a lesser extent, in North America, faces competitive pressures from companies with facilities in the Middle East, which enjoy substantial cost advantages due to access to low-cost gas feedstock available in this region. These cost advantages are particularly significant when oil prices are high, as has been the case in recent years. The competitive pressure we experience could be exacerbated if the Chinese economy fails to grow as expected, in which case more of the product manufactured in the Middle East to meet the growth expected for China could be redirected to Europe and North America, potentially resulting in greater supply to these markets.

      In addition, we and other petrochemical companies with a large asset base in Europe face pressures due to the fact that many of our key customers in Europe are subject to competition from low-cost producers in Asia. If our European customers are unable to successfully compete with Asian manufacturers, they could reduce their purchases from us or cease making such purchases altogether. To a lesser extent, this danger also exists in North America. Each of these risks could materially adversely affect our business, results of operations and financial condition.

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While our strategy is to build one or more petrochemical complexes through joint ventures in regions with access to low-cost feedstocks, including the Middle East and north Africa, we may not be successful in doing so.

      To gain access to low-cost feedstocks, we are actively looking at various options for constructing one or more petrochemical complexes in the Middle East or north Africa through joint ventures. On June 8, 2005, we signed a nonbinding memorandum of understanding to construct a cracker and associated derivative complex in Saudi Arabia. However, we cannot assure you that we ultimately will reach a final agreement with our Saudi partner and the Saudi Arabian government on commercially reasonable terms, that we will secure feedstock on commercially advantageous terms or that we will succeed in constructing and operating the planned complex or any similar facility on the envisaged time schedule or at all. In addition, any of these projects could require us to expend substantial amounts of cash and incur debt and could divert management’s attention from our operations. If any of these risks materializes, our business, results of operations and financial condition could be materially adversely affected.

In aggregate, we consume more ethylene and propylene than we produce at our own crackers. If the overall margin in the petrochemical value chain becomes more concentrated in the olefins business, we will be at a competitive disadvantage compared with more fully integrated competitors, and our results could be materially adversely affected.

      In Europe, we consume more ethylene than we produce, and in North America and Europe our consumption of propylene exceeds our production. To redress our olefins shortage, we purchase ethylene and propylene on the merchant market through supply contracts and swaps with other petrochemical and refining companies, including BP. To the extent olefins suppliers are able to increase their portion of the overall margin in the petrochemical value chain, there will be a corresponding decrease in the portion of the overall margin that their customers earn on processing olefins into polymers and derivatives. Because we are a net purchaser of olefins, if the overall margin becomes more concentrated in the olefins business, we will become less profitable than our more fully integrated and balanced competitors, and our business, results of operations and financial condition could be materially adversely affected.

We may experience reliability problems despite the fact that we have made significant investments in recent years to improve the reliability of some of our facilities in North America and Europe.

      We faced major reliability problems in 2000 and 2001, principally at our sites in Chocolate Bayou, Texas, and Grangemouth, United Kingdom, and, to a lesser extent, at our site in Lavéra, France. In the case of Grangemouth, the incidents culminated in a government inspection and the imposition of fines. We have invested in our facilities to address these issues. While we believe that these investments have resulted in better reliability, we have continued to experience reliability issues, and there can be no assurance that we will not experience similar problems in the future.

      In addition, we may be required to shut down facilities as a result of reliability problems and incidents at other companies’ facilities, including facilities owned and operated by BP, if these facilities are located at or near the same site as our facilities or if we otherwise depend on them. Any of these reliability issues could materially adversely affect our business, results of operations and financial condition.

Several of our petrochemical facilities are owned and operated in joint ventures with third parties. We do not control these joint ventures, and actions taken by any of the joint ventures could materially adversely affect our business.

      Several of our petrochemical facilities are owned and operated by joint ventures between us and one or more third parties. These facilities include the facility in Lavéra, France, various units of which are operated by joint ventures between us and Total, S.A. (Total), and the facility in Cedar Bayou, Texas, which is operated by Chevron Phillips Chemical Company LLC (Chevron Phillips) in a 50/50 joint venture between us and Chevron Phillips. In addition, we have recently agreed to contribute our European polystyrene and expandable polystyrene (EPS) businesses to a 50/50 joint venture with NOVA Chemicals Corporation (NOVA). While we have a certain amount

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of influence over each of these joint ventures, we do not control them and are therefore dependent on our respective joint venture partners to cooperate with us in making decisions regarding the relevant joint venture. Moreover, the day-to-day operation of the relevant facilities is the responsibility of the respective joint venture or our respective joint venture partner. Therefore, our ability to influence these operations on a day-to-day basis is limited and we may be unable to prevent actions that we believe are not in the best interests of the relevant joint venture or our company as a whole. Any such actions could materially adversely affect our business, results of operations and financial condition.

Some of our competitors are larger and more integrated and have greater financial resources.

      Competition in the petrochemical industry is based primarily on price and to a lesser extent on product performance, product quality, product deliverability and customer service. Some of our competitors are larger and more vertically integrated than we are and therefore may be able to manufacture products more economically than we can. In addition, some of our competitors have greater financial resources than we do, which may enable them to invest more capital in their business, including in their facilities and their research and technology (R&T) activities. Larger, more integrated companies with greater financial resources may be able to compete more effectively than we can, which could have a material adverse effect on our business, results of operations and financial condition.

We are subject to a variety of operational hazards and potential product liability claims, and we may not be able to maintain sufficient insurance against these risks or insurance may be unavailable to us.

      Our operations are subject to operational hazards inherent in the manufacturing and distribution of our products. These hazards include explosions, fires, severe weather and natural disasters, mechanical failures, unscheduled downtimes, pipeline leaks and ruptures, transportation interruptions, human error, spills, discharges or releases of toxic or hazardous substances or gases, storage tank leaks, and safety and security risks relating to the transport of a variety of hazardous and non-hazardous raw materials, intermediates and finished products.

      In addition to the operational hazards described above, we may become subject to product liability claims arising out of the use of, or exposure to, our products. While most of our products have some hazardous properties, some of them, such as acrylonitrile, require specialized handling procedures due to their acute and chronic toxicity. Furthermore, our polymer products have widespread end-uses in a variety of consumer industries, including in food packaging and medical applications.

      If any of these risks were to materialize and cause bodily injury or loss of life, severe damage to, or destruction of, property and equipment or environmental damage, our operations could be suspended and we could become subject to civil and criminal penalties and liabilities, which could have a material adverse effect on our business, results of operations and financial condition.

      As part of the BP group, we did not purchase third-party insurance coverage for the risks described above. In connection with our separation from BP, we have purchased limited insurance coverage for the above types of risks. In addition, we may, prior to the offering, seek to obtain insurance coverage at levels which we believe are appropriate for the size of our company and the nature of the risks we face. However, we will not seek full insurance against all potential risks incident to our business and may not obtain full coverage for all types of damage we may cause. Moreover, as a result of market conditions, premiums and deductibles for certain insurance policies may increase substantially and, in some instances, insurance may be available only for reduced amounts of coverage or at high premiums. If we were to incur a significant liability for which we are not adequately insured, our business, results of operations and financial condition could be materially adversely affected.

Because our operations are subject to numerous environmental, health, safety and other laws and regulations, we could become exposed to liability and be required to spend substantial amounts on environmental, health and safety compliance and remediation.

      Our operations and the products we make are subject to numerous environmental, health and safety laws and regulations in countries in which we operate and sell our products, including laws and regulations governing

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emissions and discharges to air and water, the handling and disposal of hazardous wastes and the remediation of contamination. In addition, some of these laws and regulations require us to hold permits in connection with our operations.

      From time to time, our facilities may experience operational problems or malfunctions, fires, storms, earthquakes or floods or other unplanned events, each of which could result in emissions or discharges in excess of applicable laws and regulations or permit limits. Any failure by us to comply with such laws and regulations or permit limits or to obtain permits could lead to, among other things, the imposition on us of civil and criminal penalties and in certain circumstances, the temporary or permanent curtailment or shutdown of a part of our operations. Moreover, if, as a result of any such failure, hazardous substances are released into the environment, the consequences could include bodily injury or loss of life, severe damage to, or destruction of, property and equipment or environmental damage.

      In addition, certain environmental laws and regulations impose liability without regard to fault for cleanup costs at contaminated sites. Given the nature of our business, we presently have environmental remediation and closure obligations at certain sites and will likely incur such obligations at additional sites, including offsite waste disposal sites, in the future. We cannot assure you that the costs associated with these obligations will not be material or exceed the accruals we have established.

      Laws and regulations affecting particular petrochemical or refined products could also have an effect on the availability or permitted use of our products, our unit costs and the prices we may charge for these products, which in turn could have an adverse effect on the profitability of these products.

      We currently incur substantial operating and capital costs for compliance with environmental, health, safety and other laws and regulations. We expect that, given the nature of our petrochemical and refining businesses, we will continue to be subject to increasingly stringent environmental, health, safety and other laws and regulations that may increase the cost of operating these businesses above currently expected levels and require substantial future capital and other expenditures. We cannot assure you that the effect of future laws and regulations on our business, results of operations and financial condition will not be material.

      If any of the events described above occurs or any of these risks materializes, our business, results of operations and financial condition could be materially adversely affected.

We depend on our senior executives and other key members of our management to implement our business strategy. If we lose and are unable to replace any of these key persons or if we are unable to attract and retain other qualified personnel, our business, results of operations and financial condition could be materially adversely affected.

      We depend on the continued employment and performance of our senior executives and other key members of our management. If any of these individuals resigns or becomes unable to continue in his or her present role and is not adequately replaced, our business operations and our ability to successfully implement our business strategies could be materially disrupted. Our performance is also dependent on our ability to identify, hire and retain key technical, support, sales and other qualified personnel. If we are unsuccessful in attracting and retaining such personnel, our business, results of operations and financial condition could be materially adversely affected.

We depend on good relations with our workforce, and any significant disruption could adversely affect us.

      We employ approximately 8,000 people, approximately 40% of whom are unionized. We enjoy good relations with our workforce, which we believe is a result of, among other things, the employment terms and conditions offered by BP. In connection with our formation as a separate legal entity, we have committed to maintaining equivalent terms and conditions for at least one year following the date of this offering. While this decision has allowed us to continue our good relations with our employees, if we were to materially change our terms and conditions of employment after the one-year period expires and our employees were to react adversely to any such changes, we could experience significant labor disputes and work stoppages at one or more of our sites. A labor disturbance or work stoppage at any of our facilities as a result of any changes to our employment

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terms and conditions or for any other reason could have a material adverse effect on that facility’s operations and, potentially, on our business, results of operations and financial condition.

If our patents are declared invalid or our trade secrets become known to our competitors, our ability to compete may be impaired.

      Proprietary protection of our technologies, including our polyethylene, polypropylene and acrylonitrile technologies, is important to our business, and we may have to rely on judicial enforcement of our patents and other forms of intellectual property protection of these technologies.

      There can be no assurance that our patents will not be challenged, invalidated, circumvented or rendered unenforceable. Furthermore, if any pending patent application filed by us does not result in an issued patent or if any patent owned by us does not provide meaningful protection, our ability to compete effectively may be adversely affected. In addition, our competitors and any other third parties may obtain patents that restrict or preclude our ability to lawfully manufacture and market our products in a competitive manner, which could materially adversely affect our business, results of operations and financial condition.

      We also rely on trade secrets to develop and maintain our competitive position. While it is our policy to enter into confidentiality agreements to protect our intellectual property, these confidentiality agreements may be breached and may not provide meaningful protection for our trade secrets in the event of an unauthorized use or disclosure. In addition, others could obtain knowledge of our trade secrets through independent development or other access by legal means. If our trade secrets become known, our business, results of operations and financial condition could be materially adversely affected.

Risks Related to Our Relationship with BP

Our historical financial results as a part of BP may not be representative of our future results as a separate, standalone company.

      Our combined financial statements and the other financial information we have included in this prospectus have been derived from BP’s consolidated financial statements and accounting records and do not necessarily reflect what our results of operations, financial condition and cash flows would have been had we operated as a separate, standalone company during the periods presented in this prospectus. BP did not account for us, and we were not operated, as a separate, standalone company for the periods presented. The historical costs and expenses reflected in our combined financial statements include an allocation for certain corporate functions historically provided to us by BP, including legal, finance, human resources and other administrative functions. These allocations were based on what we and BP considered to be reasonable reflections of the historical utilization levels of these functions required in support of our business. Moreover, our combined financial statements and the other historical financial information included in this prospectus do not necessarily indicate what our results of operations, financial condition, cash flows or costs and expenses will be in the future. The adjustments made to arrive at our unaudited pro forma combined financial statements reflect, among other things, changes in our funding and operations as a result of our separation from BP. However, there can be no assurance that these adjustments will reflect our funding and operating costs as a separate, standalone company. For more information on our results of operations, financial condition and cash flows, see “Selected Combined Financial Data,” “Unaudited Pro Forma Combined Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the combined financial statements and the accompanying notes included elsewhere in this prospectus.

BP provides us with a substantial proportion of our feedstock requirements and several of our sites depend entirely on BP for their supply of raw materials.

      BP accounts for a substantial proportion of our refining and petrochemical feedstock requirements. While the substantial majority of these feedstocks are secured by long-term contracts, BP may terminate each of these agreements for cause. If we lose BP as a supplier or if, as a result of operational problems at any of its facilities, BP is unable or unwilling to supply us with raw materials in the required quantities or at all, we could experience temporary disruptions which could force us to shut down facilities. In addition, we could experience substantial

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delays in finding suitable replacement feedstocks on commercially viable terms. At sites which are deeply integrated with BP’s facilities and therefore depend entirely on BP for the supply of raw materials, we may be unable to find a suitable alternative supplier. For example, our facilities in Carson, California and Texas City, Texas depend on raw materials from the respective BP refineries located on the same sites and have no convenient access to alternative supply channels. If BP fails to supply us with raw materials at any of these sites, we may be forced to shut the affected facilities, either temporarily or permanently. If any of these risks materializes, our business, results of operations and financial condition could be materially adversely affected.

We currently rely on BP for a variety of specialized support services, including with respect to commercial optimization, commodity trading, hedging and operational support. We cannot assure you that the transitional support BP has agreed to provide to us in these areas will be sufficient for our needs or that we will be able to develop equivalent in-house expertise or replace these services by contracting with third parties.

      We have historically relied on BP for assistance with the optimization of purchases and sales of refinery and petrochemical feedstocks on the international commodity markets, the off-take of refinery products and related commodity trading and hedging activities. In addition, BP has provided us with operational assistance, including in the areas of technical support, shipping and transportation. BP has agreed to continue to provide us with these services for a limited period of time through a series of arrangements with BP’s supply and trading operations. While the term and termination provisions of the relevant agreements vary based on the service being provided, several of these agreements may be terminated at the end of 2006. In addition, BP has agreed to provide certain transitional support services to us, including services related to information technology systems, marketing, treasury functions, human resources management and financial, tax and accounting services. Most of these services are provided under agreements which terminate no later than December 31, 2006.

      We intend to develop capabilities to provide many of the services for which we currently rely on BP during the term of the relevant agreements. However, although we have attempted to structure these agreements to meet our needs, there can be no assurance that in the case of a conflict of interest BP will not prioritize its own business interests. Moreover, we may fail to effectively develop the capabilities for which we currently rely on BP. In addition, the level of expertise we may ultimately acquire could be lower than that which BP possesses. Moreover, because of our smaller scale and, consequently, relatively weaker financial position than BP, we may be less competitive when operating independently in the commodity markets.

      If we fail to adequately replace the functions for which we currently rely on BP, or are unable to enter into alternative arrangements with third parties on commercially viable terms, our business, results of operations and financial condition could be materially adversely affected.

As a standalone company, we may have less purchasing power and therefore could experience higher costs.

      As a part of BP, we were able to take advantage of BP’s large size and purchasing power in procuring feedstocks, other raw materials and supplies, and technology and support services, including employee benefit support and audit services. Following the separation, we will be a smaller and less diversified company and will not have access to financial and other resources comparable to those of BP. Accordingly, we may be unable to buy feedstocks, other raw materials and supplies, technology and support services or sell products at prices and on terms as favorable as those which were available to us prior to the separation, which could increase our operating costs and have a material adverse effect on our business, results of operations and financial condition.

We may from time to time experience conflicts of interest in our relationship with BP, and, because BP owns a controlling stake in us, the resolution of these conflicts may not be on the most favorable terms for us.

      We may from time to time have conflicts of interest with BP with respect to our relationship and the resolution of these conflicts may not be on the most favorable terms for us. Conflicts of interest may arise between us and BP in a number of areas including:

•  direct or indirect competition between us and BP, for example, due to the fact that we both operate refineries in Europe, and the fact that BP holds interests in joint ventures which operate petrochemical facilities in China, Malaysia and Germany;

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•  tax, labor, employee benefit, environmental, indemnification and other matters arising from our separation from BP;

•  intellectual property matters;

•  employee recruiting and retention;

•  the transfer by BP of all or a portion of its ownership interest in us to a third party;

•  the nature, quantity, quality, time of delivery and pricing of products we supply to each other under our supply agreements with BP;

•  business combinations involving our company; and

•  business opportunities that may be attractive to both BP and us.

      Following the completion of the offering, BP will own      % of our shares. Although we and BP have attempted to structure our ongoing commercial relationships on an arm’s length basis, if a conflict of interest were to arise in the future, we may not be able to successfully resolve that conflict, and even if we manage to do so, there can be no assurance that the resolution would be as favorable as if we were dealing with an unaffiliated third party. In each such case, our business, results of operations and financial condition could be materially adversely affected.

Several of our directors are currently employees of BP. In addition, most of our directors and executive officers own BP common stock or options to acquire shares of BP common stock. These directors and executive officers potentially have conflicts of interest, which they may not resolve in our favor.

      Several of our directors are currently employees of BP and will continue their employment relationship with BP after the offering. In addition, several of our directors and executive officers own BP common stock, options to acquire BP common stock and other equity securities of BP and will continue to do so after the offering. Each of these relationships could create, or appear to create, potential conflicts of interest when those directors and officers are faced with decisions that potentially have different implications for BP than they do for us. While our directors, executive officers and members of our senior management are legally required to act in our best interests, we cannot assure you that no conflicts of interest between their duties and interests as our employees and their affiliation with BP will arise or that they will resolve any such conflicts in our favor. See “Management” for a description of the extent of the relationship between our directors, officers and senior management on the one hand and BP on the other hand.

The reorganization agreements we have entered into with BP in connection with our establishment as a separate, standalone company require us to assume certain past, present and future liabilities related to our business and may be less favorable to us than if we had acquired a separate business from an unaffiliated third party.

      Pursuant to the agreements we have entered into with BP in connection with our formation as a separate legal entity within the BP group, we have agreed to indemnify BP for certain past, present and future liabilities related to our business, including liabilities arising from facts and events that currently may be unknown to us. BP has transferred to us certain assets and liabilities formerly included in BP’s Petrochemicals, Refining and Marketing and Gas, Power and Renewables segments. In connection with these transfers, we have generally assumed all historic liabilities (other than tax liabilities) relating to the assets we acquired, and we will retain substantial environmental remedial or closure obligations relating to conditions at our facilities, irrespective of whether they occurred before or after the transfers. We provided BP with an indemnity in relation to our business and the liabilities we have assumed in connection with these transfers. Although we and BP have attempted to structure these agreements on an arm’s length basis, there can be no assurance that the allocation of assets and liabilities between us and BP set forth in these agreements is as favorable to us as the allocation we would have been able to agree upon if we had acquired a separate business from an unaffiliated third party.

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BP has agreed to indemnify us for certain liabilities. However, there can be no assurance that we will be able to enforce any claims under this indemnity against BP.

      In connection with our separation from BP, BP has agreed to indemnify us, subject to certain limitations, for certain liabilities, including any claims and losses we may incur with respect to:

•  any liabilities related to off-site waste disposal prior to April 1, 2005 (excluding liabilities related to certain waste disposal sites located near our facilities in Cologne, Germany and Sarralbe, France);

•  any liabilities related to former facilities which, as of April 1, 2005, had been sold, closed or decommissioned;

•  any claims for exposure to hazardous materials at our facilities to the extent that such claims were either made prior to April 1, 2005 or threatened in writing prior to April 1, 2005 and made prior to April 1, 2006 or, in certain cases, to the extent that such exposure related to events that occurred prior to April 1, 2005; and

•  certain product liability claims related to products manufactured prior to April 1, 2005.

      Nonetheless, third parties could seek to hold us responsible for any of the liabilities BP has agreed to retain, and there can be no assurance that we will be able to enforce our claims under the indemnity against BP. Moreover, even if we ultimately succeed in recovering any amounts for which we are held liable from BP, we may be required to temporarily bear these losses ourselves. Each of these risks could materially adversely affect our business, results of operations and financial condition.

Risks Related to the Ownership of Shares of Our Common Stock

There has been no prior market for our shares, and our share price could fluctuate significantly.

      Prior to the offering, there has been no trading market for our shares. We intend to apply to list our shares on the NYSE. However, our share price may fluctuate significantly, depending on many factors, including the perceived prospects of our business and the petrochemical and refining industries in general, differences between our actual financial position and results of operations and those expected by investors and analysts, changes in analysts’ recommendations or projections, changes in general economic or market conditions and broad market fluctuations. In recent years, the securities markets have experienced substantial volatility in prevailing price levels that is unrelated or disproportionate to the operating performance of individual companies. Accordingly, our shares may trade at a price significantly below the initial public offering price of our shares.

The future sale of a substantial number of our shares by BP or the perception that such sales may occur could adversely affect our share price.

      Following completion of the offering, BP will own      % of our shares, assuming the over-allotment option is not exercised. In connection with the offering, BP has agreed to certain restrictions on the sale or other disposition of its shares under a lock-up agreement. See “Underwriting” for more information on BP and on the restrictions BP has agreed to with respect to the sale or other disposition by BP of its shares in our company. After the expiration of this period, BP could sell or otherwise dispose of these shares in a public offering, spin-off or other transaction. BP has announced that it will consider sales of its remaining shares in our company following the completion of the offering. Any sale or other disposition by BP of a substantial number of our shares in the public market or to its shareholders or the possibility that such a sale or distribution may occur could have a material adverse effect on our share price. Pressure on our share price could also result if BP decided to sell some or all of its shares in our company to a financial or strategic buyer and the financial markets perceived that transaction as not being in the best interests of our shareholders.

After completion of the offering, BP will continue to own a controlling stake in our company and as a result will be able to exercise significant control over our company, which may adversely affect your interests.

      Following completion of the offering, BP will own      % of our shares, and new investors who purchase shares in the offering will own      % of our shares. As a result, BP will be in a position to control the outcome of

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corporate actions with respect to our company in a manner that could conflict with our interests. Examples of such corporate actions include:

•  amending our corporate documents;

•  determining the amount and timing of dividends paid to itself and other shareholders;

•  changing the size and composition of our Board of Directors and committees of our Board of Directors;

•  otherwise controlling management and operations and the outcome of matters submitted for a shareholder vote; and

•  preventing a business combination or other change in control in the future that might affect our share price.

Certain provisions of our charter and bylaws, the laws of Delaware and our agreements with BP could make a takeover more difficult and could adversely affect our share price.

      Certain provisions of our agreements with BP and our charter and bylaws as well as the laws of Delaware could make a takeover of our company more difficult, which could adversely affect our share price. Under our agreements with BP, for so long as the BP group beneficially owns at least 50% of the voting power of the outstanding shares of our capital stock entitled to vote, we are required to obtain BP’s consent prior to issuing shares of common stock or securities convertible or exchangeable into or exercisable for our common stock if, after giving effect to such issuances, the BP group would own less than 50% of the voting power of the outstanding shares of our capital stock. In addition, for so long as the BP group beneficially owns at least 10% of the outstanding shares of our capital stock entitled to vote, in any future issuances of shares of our common stock or other securities described above, BP will be entitled to a preemptive right to purchase such number of shares as is necessary to allow it to maintain the percentage of its voting power, with certain exceptions.

      Certain provisions of our charter and bylaws could make it difficult for someone to acquire control of our company in a transaction not approved by our Board of Directors. These provisions include the authorization of the issuance of “blank check” preferred stock without the need for action by our shareholders, restrictions on the ability of our shareholders to remove directors, restrictions on the ability of our shareholders to call special meetings of our shareholders, supermajority voting requirements for shareholders to amend certain provisions of our organizational documents, the authorization to establish a classified Board of Directors, advance notice requirements for nominations of directors or for proposals by directors to be acted upon at shareholders’ meetings, special quorum requirements for meetings of our Board of Directors and limitations on the ability of our shareholders to act by written consent. Some of these provisions, such as supermajority voting requirements for shareholders to amend certain provisions of our organizational documents, are effective for so long as the BP group’s or its designated direct transferee’s beneficial ownership of our company meets certain thresholds, and some of these provisions, such as the limitation on shareholder action by written consent, become effective once BP group’s or its designated direct transferee’s beneficial ownership of our company falls below 50%. See “Description of Capital Stock — Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation and Bylaws.”

      Our certificate of incorporation also provides that Section 203 of the Delaware General Corporation Law will not apply to us for so long as the BP group or any designated direct transferee of the BP group beneficially owns at least 20% of the outstanding shares of our common stock. If the ownership interest of the BP group or any of its designated direct transferees falls below 20%, we will be subject to Section 203 of the Delaware General Corporation Law, which will prohibit us, in certain situations, from entering into a business combination with a shareholder owning 15% or more of our shares for a period of three years after the shareholder attains that status. These provisions could also discourage proxy contests and make it more difficult for you and other shareholders to elect directors other than the candidates nominated by our Board of Directors. The existence of these provisions could adversely affect our share price. Although such provisions do not have a substantial practical significance to investors while BP controls us, they could have the effect of depriving our shareholders of an opportunity to sell their shares at a premium over prevailing market prices should BP’s combined voting power fall below the relevant thresholds.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS AND MARKET DATA

      This prospectus includes forward-looking statements. When used in this document, the words “anticipate,” “believe,” “estimate,” “forecast,” “expect,” “intend,” “plan” and “project,” and similar expressions, as they relate to us, our management or third parties, identify forward-looking statements. Forward-looking statements include statements regarding our business strategy, financial condition, results of operations, and market data, as well as any other statements which are not historical facts. These statements reflect beliefs of our management as well as assumptions made by our management and information currently available to us. Although we believe that these beliefs and assumptions are reasonable, the statements are subject to numerous factors, risks and uncertainties that could cause actual outcomes and results to be materially different from those projected. These factors, risks and uncertainties include those listed under “Risk Factors” and elsewhere in this prospectus and expressly qualify all subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf. Except for any ongoing obligation to disclose material information as required by the federal securities laws, we do not have any intention or obligation to update forward-looking statements after we distribute this prospectus.

      In addition, this prospectus contains information concerning the petrochemical and refining industries, our market segments and product areas generally which is forward-looking in nature and is based on a variety of assumptions regarding the ways in which the petrochemical and refining industries, our market segments and product areas will develop. We have based these assumptions on information currently available to us, including through the market research and industry reports referred to in this prospectus. Although we believe that this information is reliable, we have not independently verified and cannot guarantee its accuracy or completeness. If any one or more of these assumptions turn out to be incorrect, actual market results may differ from those predicted. While we do not know what impact any such differences may have on our business, if there are such differences, our future results of operations and financial condition and the market price of our shares of common stock could be materially adversely affected.

19

DIVIDEND POLICY

      Upon completion of the offering, our Board of Directors intends to adopt a policy of declaring, subject to legally available funds, a quarterly cash dividend on each share of common stock at an annual rate initially equal to approximately           of the initial public offering price, commencing with the first quarter of 2006.

      Our Board of Directors may at any time modify or revoke our dividend policy with respect to the common stock. Any future payment of dividends will be at the discretion of our Board of Directors and will be dependent on our net income, results of operations, financial condition, capital requirements, any contractual restrictions and other factors that our Board of Directors may consider relevant.

20

CAPITALIZATION

      The following table sets forth our cash and cash equivalents, short-term debt and capitalization as of June 30, 2005 (1) on an actual basis and (2) as adjusted to reflect the recapitalization of our company prior to the offering, as part of which our share capital will be increased to shares of common stock, par value $0.01 per share.

      You should read the information in the following table together with “Selected Combined Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the combined financial statements, the interim unaudited combined condensed financial statements and the accompanying notes included elsewhere in this prospectus.

		As of June 30, 2005
		Actual		As adjusted
		($ in millions)
Cash and cash equivalents			—
Short-term debt (including current portion of long-term debt)			1,700
Long-term debt			—
Shareholders’ equity
Shares of common stock, par value $0.01 per share
	shares of common stock authorized
	shares of common stock issued and outstanding pro forma as adjusted
Additional paid-in capital
Parent net investment			6,174
Accumulated other comprehensive income, net of tax			1,117
Total shareholders’ equity			7,291
Total capitalization			7,291

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SELECTED COMBINED FINANCIAL DATA

      The following table presents our selected combined financial data. The selected combined statements of operations data for the years ended December 31, 2002, 2003 and 2004, the selected combined statements of cash flows data for the years ended December 31, 2002, 2003 and 2004 and the selected combined balance sheet data as of December 31, 2003 and 2004 have been derived from our audited combined financial statements included elsewhere in this prospectus. The unaudited selected combined statements of operations data for the years ended December 31, 2000 and 2001 and the six months ended June 30, 2004 and 2005, the unaudited selected combined statements of cash flows data for the years ended December 31, 2000 and 2001 and the six months ended June 30, 2004 and 2005 and the unaudited combined balance sheet data as of December 31, 2000 and 2001 and June 30, 2005 have been derived from our unaudited accounting records for those periods. The unaudited selected combined financial data have been prepared on a basis consistent with our audited combined financial statements and, in the opinion of management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of such data. The selected combined financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the combined financial statements and the accompanying notes included elsewhere in this prospectus.

																As of and for the
		As of and for the														six months ended
		year ended December 31,														June 30,
		2000(1)		2001(1)			2002			2003			2004			2004			2005
		($ in millions)
Combined Statements of Operations Data
Revenues			10,599		9,898			11,776			13,422			17,937			7,791			11,131
Cost of sales								(10,775	)		(12,586	)		(16,765	)		(7,253	)		(9,876	)
	Gross margin							1,001			836			1,172			538			1,255
Selling, general and administrative expenses								(734	)		(616	)		(630	)		(341	)		(341	)
Research and development expenses								(120	)		(115	)		(137	)		(64	)		(51	)
Restructuring and asset impairment charges								(93	)		(72	)		(345	)		(5	)		(21	)
	Operating profit							54			33			60			128			842
Equity (loss) income from investments in affiliates								(2	)		9			8			5			4
Interest expense								(35	)		(44	)		(49	)		(25	)		(25	)
Other income (expense), net								(65	)		(123	)		(24	)		27			(42	)
	Income (loss) from continuing operations before income taxes							(48	)		(125	)		(5	)		135			779
	Provision for income taxes for continuing operations							(118	)		(90	)		(128	)		(86	)		(233	)
	Net income (loss) from continuing operations		456		(758	)		(166	)		(215	)		(133	)		49			546
	Loss from discontinued operations, net of income tax expense (benefit) of $0, $0, $(52) million, $0 and $0							(29	)		(25	)		(128	)		(11	)		(3	)
	Net (loss) income							(195	)		(240	)		(261	)		38			543

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														As of and for the
	As of and for the													six months ended
	year ended December 31,													June 30,
	2000(1)		2001(1)		2002			2003			2004			2004			2005
	($ in millions)
Combined Statements of Cash Flows Data
Net cash provided by operating activities of continuing operations						177			695			383			513			764
Net cash used in investing activities of continuing operations						(579	)		(561	)		(565	)		(218	)		(250	)
Net cash provided by (used in) financing activities of continuing operations						422			(140	)		203			(260	)		(559	)
Combined Balance Sheet Data
Current assets									3,520			4,398						5,129
Property, plant and equipment, net									7,050			7,136						6,737
Total assets		7,483		9,347		10,107			11,456			12,214						12,463
Current liabilities									2,085			2,210						4,508
Long-term debt		1,023		1,011		1,423			1,585			1,729						—
Total liabilities									4,937			5,201						5,172
Minority interest									1,242			—						—
Parent net investment									4,095			5,548						6,174
Accumulated other comprehensive income, net of tax									1,182			1,465						1,117
Supplemental Information
Adjusted EBITDA from continuing operations (2)						442			472			869			404			1,088

(1)	Selected financial data disclosed as of and for the years ended December 31, 2000 and 2001 is limited to revenues, net income (loss) from continuing operations, total assets and long-term debt, as this is the only financial information required to be disclosed as of these dates and the years then ended.
(2)	See “Selected Combined Financial Data — Use of Non-GAAP Financial Measures” for a definition of adjusted EBITDA and the reasons why management believes that the presentation of adjusted EBITDA provides useful information to investors. Set forth below is a reconciliation of net (loss) income to adjusted EBITDA for each period indicated:

										For the six
	For the year ended									months ended
	December 31,									June 30,
	2002			2003			2004			2004		2005
	($ in millions)
Net (loss) income		(195	)		(240	)		(261	)		38		543
Loss from discontinued operations		29			25			128			11		3
Interest expense		35			44			49			25		25
Provision for income taxes for continuing operations		118			90			128			86		233
Depreciation and amortization from continuing operations		423			517			545			244		284
Asset impairments from continuing operations		32			36			280			—		—
Adjusted EBITDA from continuing operations		442			472			869			404		1,088

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Use of Non-GAAP Financial Measures

      Adjusted EBITDA is a non-GAAP measure and is defined as net income (loss) from continuing operations before interest expense, provision for income taxes for continuing operations, depreciation and amortization from continuing operations and asset impairments from continuing operations. We believe that the presentation of adjusted EBITDA enhances an investor’s understanding of our financial performance. However, adjusted EBITDA should not be considered in isolation or viewed as a substitute for net income, cash flow from operations or other measures of performance as defined by U.S. GAAP. Adjusted EBITDA, as used herein, is not necessarily comparable to other similarly titled captions of other companies due to potential inconsistencies in the method of calculation. Our management uses adjusted EBITDA to assess our company’s operating performance and to make decisions about allocating resources among our various segments. In assessing our overall performance and the performance of each of our segments, management reviews adjusted EBITDA as a general indicator of performance compared to prior periods. Adjusted EBITDA excludes losses related to discontinued operations, interest expense, provisions for income taxes for continuing operations, depreciation and amortization from continuing operations and asset impairments from continuing operations, which are items that management does not utilize in assessing operating performance. Our management believes it is useful to eliminate these items because it allows management to focus on what it considers to be a more meaningful indicator of our operating performance and ability to generate cash flow from operations. As a result, internal management reports used during monthly operating reviews feature adjusted EBITDA. Nevertheless, management recognizes that there are limitations associated with the use of adjusted EBITDA as compared to net income, which reflects overall financial performance, including the effects of interest, taxes, depreciation and amortization and asset impairments, and therefore uses adjusted EBITDA in conjunction with traditional GAAP operating performance measures as part of its overall assessment of our performance.

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UNAUDITED PRO FORMA COMBINED FINANCIAL DATA

      We have derived the unaudited pro forma combined financial statements set forth below from our audited combined financial statements for the year ended December 31, 2004 and our unaudited combined financial statements for the six months ended June 30, 2005, each of which is included elsewhere in this prospectus.

      The unaudited pro forma combined statements of operations reflect the combined operations of our company and our subsidiaries as if our separation from BP and the related transactions described below had occurred as of January 1, 2004. The unaudited pro forma combined balance sheet reflects the combined operations of our company and our subsidiaries as if our separation from BP and the related transactions described below had occurred as of June 30, 2005.

      You should read the unaudited pro forma financial statements reported below in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the combined financial statements and the notes thereto included elsewhere in this prospectus.

      The unaudited pro forma combined financial statements do not necessarily reflect what our financial position and results of operations actually would have been had our separation from BP and the related transactions described below occurred on the dates indicated nor do they purport to project our future financial performance. BP did not account for us, and we were not operated, as a separate legal entity for any period prior to April 1, 2005.

      The unaudited pro forma combined financial statements give pro forma effect to:

•  the recapitalization of our company prior to the offering, as part of which our share capital will be increased to                shares of common stock, par value $0.01 per share;

•  our repayment on March 22, 2005 of loans in the amount of $1,755 million which were secured by the petrochemical assets of our site in Grangemouth, United Kingdom, and the replacement of this debt by a loan from BP to us in the amount of $1,700 million, which was granted to us effective April 1, 2005;

•  the transfer from BP to us of the road and rail terminals of our Grangemouth site, which are not included in our historical combined financial statements; the relevant assets will be transferred to us prior to the offering, effective April 1, 2005;

•  the transfer from us to BP of our proportionate share of the shared power station of the Grangemouth site and certain infrastructure shared between us and BP at our site in Geel, Belgium; our historical combined financial statements show our proportionate share of these assets; the relevant assets were transferred from us to BP prior to the offering, effective April 1, 2005;

•  the transfer from us to BP of our obligations under certain pension and other post-employment benefit plans relating to former employees to reflect the fact that BP has agreed to retain these obligations;

•  the commercial arrangements entered into between us and BP effective January 1, 2005; and

•  insurance costs we expect to incur as a result of operating as a standalone company.

      In the year ended December 31, 2004 and the six months ended June 30, 2005, BP allocated to us general and administrative (including head office) expenses in the amount of $259 million and $8 million, respectively. General and administrative expenses include costs related to human resources, legal, treasury, insurance, finance, internal audit, strategy, public affairs and other services but do not include selling-related expenses. Effective January 1, 2005, we assumed responsibility for substantially all of these services and related costs and therefore the charges allocated to us by BP are expected to be substantially lower in 2005. We expect our general and administrative expenses, in aggregate, to be approximately $320 million in 2005. No pro forma adjustments have been made to our combined financial statements to reflect the costs and expenses described in this paragraph, except for additional costs related to our standalone insurance policies described in note (d) below.

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      The following table shows our unaudited pro forma combined statements of operations for 2004 and the six months ended June 30, 2005:

		For the year ended									For the six months ended
		December 31, 2004									June 30, 2005
					Pro forma			Pro forma						Pro forma			Pro forma
		Historical			adjustments			combined			Historical			adjustments			combined
		($ in millions, except per share amounts)
Pro forma combined statement of operations
Revenues			17,937			(2	)(a)		17,935			11,131						11,131
Cost of sales			(16,765	)		(2	)(b)		(16,768	)		(9,876	)		2	(b)		(9,874	)
						(1	)(c)
Gross margin			1,172			(5	)		1,167			1,255			2			1,257
Selling, general and administrative expenses			(630	)		(50	)(d)		(680	)		(341	)					(341	)
Research and development expenses			(137	)					(137	)		(51	)					(51	)
Restructuring and asset impairment charges			(345	)					(345	)		(21	)					(21	)
Operating profit			60			(55	)		5			842			2			844
Equity income (loss) from investments in affiliates			8						8			4						4
Interest expense			(49	)		58	(e)		(46	)		(25	)		14	(e)		(26	)
						(55	)(f)								(15	)(f)
Other income (expense), net			(24	)		9	(a)		(49	)		(42	)					(45	)
						1	(c)								(3	)(g)
						(35	)(g)
Income (loss) from continuing operations before income taxes			(5	)		(77	)		(82	)		779			(2	)		777
Provision for income taxes for continuing operations			(128	)		29	(h)		(99	)		(233	)		1	(h)		(232	)
Net (loss) income from continuing operations			(133	)		(48	)		(181	)		546			(1	)		545
Net (loss) income per share(i)
	Basic
	Diluted
Average number of shares used in computing net (loss) income per share
	Basic
	Diluted

(a)  Represents (1) a decline in revenues, reflecting the fact that in some cases our agreements with BP effective January 1, 2005 relating to the purchase and sale of refinery products have a different economic effect than the intra-group arrangements which governed our relationship with BP historically; and (2) other income in the form of fees received by us from BP to compensate us for inventories held by us to support BP’s inventory maintenance obligations in certain countries.

	For the year ended
	December 31, 2004
	($ in millions)
Revenues		(2	)
Other income		9
Net adjustment		7

(b)  Represents the net effect of (1) reversing costs associated with retired employees participating in our German pension and post-employment benefit plans to reflect the fact that BP has agreed to retain all obligations to retirees under these plans, (2) eliminating the financing and amortization component from expenses associated with the participation of our employees in BP’s group-wide pension and post-employment benefit plans to reflect our agreement with BP that in the future we will only be responsible for the service cost

26

component of these plans (for U.K. plans, this agreement results in an increase in our costs due to the fact that our historical pension costs were reduced by a surplus generated by BP’s pension plan in the United Kingdom; in all other relevant jurisdictions the agreement has the opposite effect) and (3) certain related adjustments.

	For the year
	ended			For the six
	December 31,			months ended
	2004			June 30, 2005
	($ in millions)
Retired employees under plans in Germany		13			4
Group-wide plans (United Kingdom)		(45	)		(8	)
Group-wide plans (other jurisdictions)		35			6
Other		(5	)		0
Net adjustment		(2	)		2

(c)  Represents (1) the impact on our depreciation charge of including in our asset base the road and rail terminals of our site in Grangemouth, United Kingdom, which are not reflected in our historical combined financial statements but will be transferred from BP to us prior to the offering, effective April 1, 2005, and (2) the impact on our depreciation charge of excluding from our asset base our proportionate share of the shared power station of the Grangemouth site and certain shared infrastructure at our Geel, Belgium, site, which will be transferred from us to BP prior to the offering, effective April 1, 2005 (we have agreed to pay to BP (A) depreciation charges for our proportionate use of these assets, which we record under cost of sales, and (B) a charge on capital on their net book value, which we record under other income (expense), net).

		For the year ended			For the six months
		December 31,			ended June 30,
		2004			2005
		($ in millions)
(Increase) decrease in depreciation charge
	Grangemouth road and rail terminal		(2	)		(1	)
	Grangemouth power station		1			0
	Geel infrastructure		1			1
Depreciation charge-back
	Grangemouth power station		0			0
	Geel infrastructure		(1	)		0
Cost of capital charge
	Grangemouth power station		1			0
	Geel infrastructure		0			0
Net adjustment			0			0

(d)	On January 1, 2005, we established our own standalone insurance policies for certain risks with BP’s captive insurance subsidiary. The cost of these policies for 2005 is expected to be approximately $38 million. Following completion of the offering, we expect to put in place a comprehensive insurance program, which is expected to cost approximately $50 million per year.
(e)	Represents the elimination of interest expense related to debt secured by our Grangemouth petrochemical assets, which is reflected in our historical combined financial statements and was repaid on March 22, 2005.

(f)  Represents interest expense for the year ended December 31, 2004 related to a loan in the amount of $1,700 million extended to us by BP effective April 1, 2005. The interest rate on the loan is LIBOR plus five basis points, with interest payable every three months. LIBOR has been calculated based on the three-month LIBOR rate as of April 1, 2005, which was 3.12%. This loan replaced the debt secured by our Grangemouth petrochemical assets, which was repaid on March 22, 2005. The loan we have been granted by BP matures on March 30, 2006, unless repaid earlier. The annual impact of an increase or decrease of 10 basis points in interest rates on the loan would reduce or increase our pre-tax income by $1.7 million. We are currently in discussions with banks for term loans and other short-term facilities with which we intend to replace this loan. Accordingly, our future interest expense may be higher or lower, depending on the maturity and interest rate of the bank financing we plan to obtain, the timing of repayment of this loan and the then-applicable LIBOR rate.

27

(g)  Represents the elimination of the net impact of foreign exchange translation gains and losses in connection with the loans secured by the Grangemouth petrochemical assets and gains and losses on derivatives used to hedge these losses at year-end exchange rates.

	For the year
	ended			For the six
	December 31,			months ended
	2004			June 30, 2005
	($ in millions)
Translation gains and losses		124			(19	)
Gains and losses on derivatives trading		(159	)		16
Net adjustment		(35	)		(3	)

(h)  Represents the tax effect of the pro forma adjustments on our net (loss) income before income taxes using the estimated effective tax rate of 38%.

(i)  The computation of pro forma net (loss) income per share is based on the anticipated number of shares of our common stock outstanding upon completion of the offering. Prior to the completion of the offering, there will be no outstanding options to purchase shares of our common stock or other potentially dilutive securities. In connection with the offering, our executive officers and certain key employees will be granted restricted shares, restricted stock units and stock options.

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     The following table shows our unaudited pro forma combined balance sheet as of June 30, 2005 along with a reconciliation to our audited combined balance sheets as of that date:

			As of June 30, 2005
					Pro forma			Pro forma
			Historical		adjustments			combined
			($ in millions)
Pro forma combined balance sheet
Assets
	Current assets
		Trade accounts receivable, net		1,923					1,923
		Receivables from affiliates		576					576
		Inventories		2,030					2,030
		Prepayments and other current assets		600					600
		Total current assets		5,129					5,129
	Property, plant and equipment, net			6,737					6,737
	Investment in and advances to affiliates			145					145
	Goodwill and intangible assets			258					258
	Deferred tax assets			61					61
	Prepayments and other assets			133					133
Total assets				12,463					12,463
Liabilities and owner’s equity
	Current liabilities
		Trade accounts payable		718					718
		Payables to affiliates		1,075					1,075
		Accrued liabilities		692		(43	)(a)		649
		Other current liabilities		323					323
		Due to parent		1,700					1,700
		Total current liabilities		4,508		(43	)		4,465
	Long-term debt			—					—
	Other liabilities			347					347
	Deferred income taxes			317					317
Total liabilities				5,172		(43	)		5,129
Owner’s equity
	Common stock						(b)
	Parent net investment			6,174		43	(a)		6,217
	Additional paid-in capital						(b)
	Accumulated other comprehensive income (loss), net of tax			1,117					1,117
Total owner’s equity				7,291		43			7,334
Total liabilities and owner’s equity				12,463					12,463

(a)	Represents the reversal of an accrual for the estimated closure costs of the Pasadena, North America site. BP operates this facility for us under a toll manufacturing agreement and will incur the closure costs.
(b)	Reflects the recapitalization of our company prior to the offering, as part of which our share capital will be increased to              shares of common stock, par value $0.01 per share.

29

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

      The following information should be read together with our selected combined financial and operating data, our unaudited pro forma financial data and the combined financial statements and notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this prospectus particularly in “Risk Factors” and “Special Note Regarding Forward-Looking Statements and Market Data.”

      “Innovene Inc.,” the “company,” “we,” “us,” and “our” each refer to Innovene Inc. and its subsidiaries, including its predecessor businesses, which comprise certain operations that were formerly part of BP’s Petrochemicals, Refining and Marketing, and Gas, Power and Renewables segments, as described under “ — Basis of Presentation,” except where the context makes clear that the reference is only to Innovene Inc. itself and not to its subsidiaries or predecessor businesses. The assets and liabilities comprising the operations of our predecessor businesses will be transferred to us prior to the completion of the offering. A glossary of petrochemical and refining abbreviations used in this prospectus is set forth on page 133.

Overview

Our Business

      We are among the world’s largest petrochemical companies, with revenues of $17.9 billion in 2004. We conduct our business through petrochemical manufacturing sites in eight countries as well as two refineries which are fully integrated with our petrochemical facilities. At June 30, 2005, our total petrochemical production capacity was approximately 40 billion pounds per year and our refineries had a combined crude oil distillation capacity of approximately 400 mbd. Our business is structured around five major sites, which account for approximately 70% of our petrochemical production volumes and approximately 85% of our overall production volumes.

      We have a global reach and leading market positions with respect to our key petrochemical products, which enable us to manage our business on a worldwide basis. We benefit from the cost advantages of operating large-scale petrochemical facilities and the high degree of integration at our major sites. We have an expanding position in the fast-growing Asian markets, which we serve through our operations in North America and Europe. We have an established regional office in Shanghai, China to manage our operations in Asia.

      Our business comprises certain assets, liabilities and associated infrastructure that were formerly part of BP’s Petrochemicals, Refining and Marketing, and Gas, Power and Renewables segments. We believe our separation from BP has created new opportunities for us. Historically, our business was a small part of a much larger organization and, our performance lagged behind that of other companies in the petrochemicals sector. As a separate entity with our own management structure, we will be able to focus on the factors that are critical to the success of our petrochemical and refining businesses and benchmark ourselves directly against the performance of our competitors. Our benchmarking work has identified significant opportunities to improve the performance and optimize the use of our existing assets and to increase our margins. We intend to pursue growth opportunities by investing in new assets and forming joint ventures in regions that have access to low-cost feedstocks.

      In connection with our formation as a separate legal entity, BP has agreed to provide various administrative and operational support services to us. In addition, we have entered into a range of commercial arrangements with BP for the supply of refining and petrochemical feedstocks, the purchase and sale of refined products, the sharing of common infrastructure and the provision of utilities at various sites which we share with BP. See “Certain Relationships and Related Transactions — Commercial Interface Agreements” for more information on these arrangements.

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Key Factors Driving Our Results

      Our results of operations are driven by a combination of factors affecting the petrochemical and refining industries as a whole and various structural and operational factors specific to our company. To improve our results, we depend on our ability to maximize our sales volumes, to realize attractive contribution margins (that is, the difference between revenues and variable costs of goods sold on a per-unit basis) and to firmly manage our fixed costs. While we have some ability to manage our revenues and feedstock costs, given the commodity nature of the petrochemical and refining industries, our contribution margins are largely driven by industry dynamics. Set forth below is an overview of the key drivers affecting our results.

      Supply and demand in the petrochemical industry. Margins in the petrochemical industry are strongly influenced by industry utilization. As demand for petrochemical products approaches available supply, utilization rates rise, and, prices and margins typically increase. Historically, this relationship has been highly cyclical due to fluctuations in supply resulting from the timing of new investments in capacity and general economic conditions affecting the relative strength or weakness of demand. Generally, capacity is more likely to be added in periods when current or expected future demand is strong and margins are, or are expected to be, high. Investments in new capacity can result, and in the past frequently have resulted, in overcapacity, which typically leads to a reduction of margins. In response, companies typically reduce capacity or limit further capacity additions, eventually causing the market to be relatively undersupplied. The bottom of the last cycle was reached in 2001 and continued through 2003 due to weak demand and substantial simultaneous capacity additions. Starting in 2004, stronger demand and limited capacity investments have led to greater contribution margins.

      In addition to the global petrochemical cycle, our results are driven by short-term fluctuations in the regional balance between the supply of products and the amount of available capacity on the one hand and the demand for products on the other hand due to planned and unplanned facility outages, which are a feature of our industry.

      Refining industry cash margins and oil price differentials. Refining industry cash margins have increased significantly since 2002, reaching near record levels in 2004 and remaining strong in the six months ended June 30, 2005. According to Purvin & Gertz, Inc. (PGI), the average cash margin for a hydrocracking refinery in Europe was $6.04 per barrel in 2004 and $6.15 per barrel in the six months ended June 30, 2005, compared with $2.73 per barrel in 2003. This increase is explained by several factors. Global demand for transportation fuels rose significantly from 2003 levels, substantially outstripping additions of refinery capacity. In addition, tightening product specifications to satisfy higher environmental standards restricted the production of certain refinery products. From a macroeconomic perspective, OPEC continued to limit supplies, keeping global inventories of both crude oil and refined products at low levels, leading to further price and margin increases. At the same time, demand for heavy/residual refinery products continued to decline, whereas incremental crude oil supplies became dominated by heavy, sour crudes. As a result, the price differential between light, sweet crude oil and heavy, sour crude oil widened substantially. According to PGI, this price differential (as measured by the Urals/ Brent differential) averaged $4.14 per barrel in 2004 and $4.33 per barrel in the six months ended June 30, 2005, compared with $1.76 per barrel in 2003. We benefited from these developments because both of our refineries have the ability to process a broad range of crude oil blends.

      Asset utilization, reliability and turnarounds. Our results of operations are materially influenced by the degree to which we utilize our assets, as measured by our production volumes relative to the capacity of our assets. The principal factors that influence our asset utilization are plant reliability, turnarounds and the balance between supply and demand for our products in the industries and regions in which we operate.

      The following table provides an overview of our asset utilization:

										For the six months
		For the year ended December 31,								ended June 30,
		2001		2002		2003		2004		2004		2005
		(%)
Utilization
	Petrochemicals(1)		85		87		87		88		88		88
	Refining(2)		81		89		90		89		85		86

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(1)

In our petrochemical business, capacity is defined as nameplate capacity. See “Business — Manufacturing — Overview” for more information on how we calculate nameplate capacity in our petrochemical business. One of the consequences of the way we calculate capacity is that reliability problems and turnarounds affect our utilization rates only to the extent that the impact of these events exceeds the estimates factored into our capacity calculations.

(2)

In our refining business, utilization is measured by reference to crude oil distillation capacity, which is calculated as the maximum crude oil volume that can be fed into a refinery using the type of crude oil that the relevant refinery was designed to process. The volume of crude oil expands during its conversion into finished refinery products. Therefore, it is not possible to directly compare the utilization rates and capacity figures of our refining business with the refining production volumes shown elsewhere in this prospectus.

     In 2000 and 2001, the utilization of our facilities was influenced by the fact that we faced reliability issues at several of our sites. See “Business — Manufacturing — Europe” for more information on these issues. We began to address these issues through targeted investments in our plants and infrastructure, workforce assessment and development programs and process automation. Since 2001, these initiatives have led to significant improvements in the reliability of our assets, particularly our olefins crackers and refineries. However, issues remain with respect to the reliability of some of our assets, in particular with respect to some of our polymers and derivatives units and, during the six months ended June 30, 2005, with respect to our refineries. We intend to build on the initial improvements we achieved in 2002 and focus our efforts on those assets with respect to which we continue to have reliability issues. Moreover, we plan to improve the reliability of our assets with remediation measures as part of the performance improvement program described below under “— Our Accelerator Program.”

      The following table provides an overview of the reliability of our facilities:

										For the six months
		For the year ended December 31,								ended June 30,
		2001		2002		2003		2004		2004		2005
		(%)
Reliability(1)
	Olefins crackers		87		97		96		96		96		95
	Polymers and derivatives units		93		95		94		94		93		94
	Refineries		90		93		94		96		95		93

(1)  The reliability of a facility is defined as the maximum sustainable daily rate (MSDR) of the facility, multiplied by the actual number of days in the period for which the calculation is made, minus volume losses during the period due to equipment or operational failures resulting in downtime or an inability to run a unit at maximum possible capacity, and the resulting net figure is divided by MSDR.

     The utilization of our facilities is also influenced by the number and length of turnarounds carried out in any given period. Turnarounds are outages of a unit scheduled to carry out necessary inspections and testing to comply with industry regulations. These outages also permit us to perform any additional maintenance activities that may be necessary. Where possible, we seek to schedule the timing of turnarounds to coincide with periods of relatively low demand for the products of the relevant units. Turnarounds of our refineries and olefins crackers typically take longer, but are less frequent, than turnarounds of our polymers and derivatives assets.

      Oil and gas price movements. Feedstock costs are the most significant component of our operating costs. The costs of the feedstocks we require to make our petrochemical products (naphtha, ethane, butane and propane) are principally driven by the price of oil and natural gas. According to the U.S. Energy Information Administration, the market price for West Texas Intermediate (WTI) crude oil increased from approximately $20 per barrel in January 2002 to approximately $57 per barrel in June 2005, while the market price for natural gas increased from $2.43 per mmbtu in January 2002 to $5.99 per mmbtu in June 2005. Our revenues increased from $11,776 million in 2002 to $13,422 million in 2003 to $17,937 million in 2004 and were $11,131 million in the six months ended June 30, 2005. The increase in revenues reflects the fact that in the recent past we have been able to pass on increases in feedstock prices to our customers in the form of higher product prices. However, our ability to do so is limited due to the impact of time lags resulting from the repricing intervals of our contracts with suppliers and customers, particularly in our petrochemical business. While most of our feedstock contracts reprice daily, our contracts with customers generally reprice on a monthly basis or, in the case of olefins contracts in Europe, quarterly. A further limitation is that many of our customers take advantage of fluctuating prices by building inventories when they expect product prices to increase and reducing inventories when they expect prices

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to decrease. The effect of these time lags and our customers’ inventory management policies on our ability to pass through feedstock price increases is magnified in periods of high volatility. In addition, changes in oil and gas prices have a direct impact on our working capital levels. In general, increases in feedstock prices lead to an increase in our working capital and decreases in feedstock prices decrease our working capital.

      Foreign exchange rate fluctuations. Although many of our sales are invoiced in local currencies, a substantial proportion of our revenues is denominated in, or linked to, the U.S. dollar. This linkage results from the fact that many of our products are subject to significant interregional trade between North America, Europe and Asia and, as a result, prices for these products tend to settle at a consistent level in U.S. dollar terms, irrespective of the currencies in which local sales and purchases are made. In markets which are smaller and more regional with limited import penetration, the linkage to the U.S. dollar tends to be weaker and, consequently, fluctuations in exchange rates have a greater impact on our reported revenues. At the same time, the majority of our non-feedstock costs are incurred in currencies other than the U.S. dollar, mostly the euro and the British pound, reflecting the fact that most of our assets are located in Europe. From January 1, 2002 to December 31, 2004, the U.S. dollar weakened against the euro and the British pound by approximately 53% and 32%, respectively. From January 1, 2005 to June 30, 2005, the U.S. dollar strengthened against the euro and the British pound by approximately 13% and 6%, respectively.

      Portfolio restructuring. Our cost structure relative to other companies in the petrochemical industry is a function of the quality and performance of our assets. We have embarked on a program to restructure and simplify our asset portfolio to reduce our costs. For example, we sold the butanediol (BDO) unit of our Lima, Ohio facility in March 2005 because it did not fit in with our overall strategy and generated operating losses since the plant opened in 2000. We report this business as a discontinued operation. Furthermore, we decided to close down the linear alpha olefins (LAO) facility in Pasadena, Texas, currently operated for us by BP under a toll manufacturing agreement, in late 2005. This decision was prompted by overcapacity in the LAO industry, the facility’s age, its outdated technology and expensive processes. The impairment charges were recorded in 2004 at the time when management made the decision to exit the butanediol business and close down the Pasadena plant. We incurred restructuring and asset impairment charges of $93 million in 2002, $72 million in 2003, $345 million in 2004, and $21 million in the six months ended June 30, 2005. On June 8, 2005, we signed a non-binding memorandum of understanding to construct a cracker and associated derivative complex in Saudi Arabia. If we enter into a definitive agreement with our partner and the Saudi Arabian government and construct a facility in this region, we would gain access to low-cost natural gas feedstock, which would improve our cost of sales position, particularly in periods when oil prices are high compared with the price for gas, as has been the case in recent years.

Recent Developments

      On August 10, 2005, we experienced a fire at one of the crackers of our Chocolate Bayou, Texas facility. The affected unit primarily produces ethylene and represents approximately 50% of our Chocolate Bayou facility’s total ethylene capacity. We are continuing to assess the operational and financial impact the incident may have on our business.

      Hurricane Katrina brought unusually severe weather conditions and caused extensive property damage to the U.S. Gulf Coast in Louisiana, Mississippi and Alabama. Although none of our plants suffered physical damage as a result of the storm, raw material suppliers and logistics providers have been affected, potentially disrupting our ability to produce and ship certain products to customers. We, and other companies in the industry, are continuing to assess the impact of Hurricane Katrina.

Our Accelerator Program

      To improve our operating results, we have embarked on a focused performance improvement program, which we refer to as our Accelerator program. The actions which we have identified under this program, and which we intend to implement over the period from 2005 to 2007, are based on a detailed analysis of our operational performance relative to our peers in the petrochemical and refining industries, and encompass all of our operations from procurement to manufacturing, sales, marketing and logistics as well as overhead costs. The

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initiatives are intended to increase our revenues, decrease our cost of sales, and reduce our selling, general, and administrative expenses, as described below:

Increase Revenues

•  Improve the availability, reliability and utilization of our facilities. We intend to improve the availability, reliability and utilization of our facilities by streamlining our management structure and establishing clear accountabilities, training our employees, improving our maintenance practices and making appropriate investments in our infrastructure. We expect to focus our maintenance efforts on facilities whose reliability was below average in 2004. We believe that this program will enable us to maximize the availability of our refineries and to operate our petrochemical facilities as close as possible to their full capacity, thereby increasing our revenues.

•  Improve our sales effectiveness. Our business optimization organization, which consists of a global network of teams drawn from our various operating units, constantly seeks to identify the best possible channel for bringing our products to market. To succeed in this effort, we depend on a strong sales force that can identify the most attractive opportunities in the market and develop offers to capture these opportunities. We recently introduced a compensation program designed to reward our sales personnel based on their success in the marketplace. In addition, starting in 2004, we took steps to renegotiate those of our polymers and derivatives contracts with customers which contained pricing provisions that either were fixed or lacked adequate flexibility to respond to changing market conditions. We believe that the inclusion of more responsive pricing provisions in our contracts will help us reduce the pressure on our contribution margins which we have historically experienced as a result of time lags due to the repricing intervals of our customer contracts, our customers’ inventory management policies and other inefficiencies in our pricing mechanisms.

Decrease Cost of Sales

•  Reduce operating and maintenance costs at our manufacturing facilities. We have recently completed an assessment of our maintenance practices and the energy utilization of our facilities. Based on these findings, we are making improvements to our maintenance practices which we expect will increase the efficiency and productivity of our plants through improved resource planning and management, while maintaining applicable Health, Safety, Security and Environmental (HSSE) standards. In addition, we have identified a number of areas in which we believe we can improve the energy utilization of our facilities, and we intend to take advantage of these opportunities to reduce our energy costs.

•  Actively manage our portfolio of assets and businesses where sufficient productivity improvements cannot be achieved. We have analyzed the competitive position and financial contribution of each of our major assets and businesses. In those cases where an asset or business is unable to perform to expectations or to contribute materially to the financial performance of our company or where it would be uneconomical to implement the necessary improvements, we will consider selling or closing the relevant asset or business. This approach has already led to the divestment of businesses and the closure of some assets in 2004 and the first six months of 2005. For example, we closed an old HDPE unit at our Grangemouth, United Kingdom site, which was expensive to operate, in March 2005, having replaced its production with a more efficient unit at our Lillo, Belgium facility. Furthermore, we signed an agreement with NOVA in May 2005 to merge our respective European polystyrene and EPS businesses into a 50/50 joint venture. We expect that these actions will reduce manufacturing costs and improve our results.

•  Simplify our product portfolio to improve utilization and increase margin contribution. To minimize the amount of production volumes lost due to transitions of our units between product grades and to maximize the utilization of our manufacturing facilities and their contribution margins, we have taken steps to simplify our product portfolio, and we intend to continue to take further steps in this direction. For example, in North America, we have reduced the number of commercial grades of our polypropylene products by approximately 40% since mid-2004. Similarly, at our Cologne, Germany site we have

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significantly reduced the number of low-density polyethylene (LDPE) grades, consistent with the commodity nature of our business.

•

Use trading markets to better optimize our feedstock and product portfolio. Although we typically derive significant value from the integration of feedstocks and product flows across our major sites, at times the commodity markets may offer more favorable commercial opportunities. Such opportunities may include reselling primary feedstocks when doing so is more valuable than processing them internally or selling olefins rather than processing them into polymers and derivatives in situations where we are able to source finished products from third parties at lower prices than the manufacturing costs we would have to incur in producing them ourselves. We intend to improve our ability to leverage these opportunities to enhance our results.

Reduce Selling, General and Administrative Expenses

•  Reduce overhead and functional costs commensurate with a standalone commodity petrochemical company. We have conducted benchmarking studies and identified savings opportunities in a number of functional areas. Each function is currently implementing improvement plans which we developed based on these studies, and we have already achieved a reduction in the number of employees engaged in our operations.

Basis of Presentation

      We were incorporated in Delaware on July 14, 2005 as a wholly-owned subsidiary of BP. Our combined statements of operations, changes in owner’s equity and cash flows for the years ended December 31, 2002, 2003 and 2004 and the six months ended June 30, 2004 and 2005 and our combined balance sheets as of December 31, 2003 and 2004 and March 31, 2005 have been derived from the consolidated financial statements and accounting records of BP, representing certain assets, liabilities and associated infrastructure of certain operations that were formerly part of BP’s Petrochemicals, Refining and Marketing, and Gas, Power and Renewables segments, and associated revenues and expenses. Specifically, BP transferred to us certain assets, liabilities and associated infrastructure relating to the former olefins and derivatives business of its Petrochemicals segment (not including joint ventures operating petrochemical facilities in China, Malaysia and Germany), refineries in Grangemouth, United Kingdom and Lavéra, France, which formed part of its Refining and Marketing segment, and a gas fractionator near Hobbs, New Mexico, which formed part of its Gas, Power and Renewables segment, in each case together with associated infrastructure. The assets and liabilities comprising the operations of our predecessor businesses will be transferred to us prior to the completion of this offering.

      Our combined statements of operations for the years ended December 31, 2002, 2003 and 2004 and the six months ended June 30, 2004 and 2005 reflect expense allocations for certain central corporate functions historically provided to us by BP, including information systems, human resources, accounting and treasury activities and legal services. These allocations reflect expenses specifically identifiable as relating to our business as well as our share of expenses allocated to us based on capital employed, capital expenditures, headcount, revenues, production volumes, fixed costs, environmental accruals or other methods our management considers to be reasonable. We and BP consider these allocations to be a reasonable reflection of our utilization of the services provided to us by BP. However, our expenses as a separate, standalone company may be higher or lower than the amounts reflected in our combined statements of operations.

Our Segments

      We report our results on the basis of five segments, O&P North America, O&P Europe, Global Derivatives, Refining and Corporate and Other. While our operating company for Europe is responsible for both our European olefins and polymers business and our refineries, management reviews the performance of these businesses separately and, accordingly, each of them is reported as a separate segment. In our O&P segments, we make olefins and related products, a broad range of polymers and various other petrochemical products directly or indirectly derived from olefins. The focus of our olefins business is on ethylene and propylene, which are the two largest volume olefins and key building blocks for polymers and derivatives. In our polymers business, we focus

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on polyethylene and polypropylene. The largest volume product of our Global Derivatives segment is acrylonitrile. Our Refining segment operates two large refineries in Grangemouth, United Kingdom and Lavéra, France. Our principal refining products are transport fuels, naphtha, and heating and fuel oils. Income and expenses associated with the operation of our regional office in Shanghai, China, the licensing of our technologies, the sales of catalysts to third parties and certain other corporate functions are reported in our Corporate and Other segment.

      The revenues of our O&P segments and our Refining segment in any given period include substantial amounts of sales between segments. All intersegmental revenues and related expenses are eliminated during consolidation. Revenues are recorded based on the source of the product sold. Accordingly, exports to Asia are recorded in the segment from which the underlying products are sourced.

      We review the performance of our segments based on adjusted EBITDA, which is the measure used by our management to assess our company’s operating performance and to make decisions about allocating resources among our various segments. See “Selected Combined Financial Data — Use of Non-GAAP Financial Measures” for a definition of adjusted EBITDA and the reasons why management believes that the presentation of adjusted EBITDA provides useful information to investors.

Results of Operations

Description of Key Line Items of our Combined Statements of Operations

      Set forth below is a brief description of the composition of the key line items of our combined statements of operations:

      Revenues. Consolidated revenues comprise sales of petrochemical and refinery products to customers and are shown net of intersegmental transactions, discounts and rebates. Each segment includes the external revenues generated by the assets included in that segment. Segmental revenues also include intersegmental sales, primarily sales of naphtha by our Refining segment to our O&P Europe segment and sales of ethylene and propylene by our O&P segments to our Global Derivatives segment. All intersegmental revenues and related expenses are eliminated during consolidation.

      Gross margin. Gross margin is calculated by subtracting cost of sales from revenues. Cost of sales comprises:

•  feedstock costs;

•  variable manufacturing and transportation costs, including the costs of catalysts, other chemicals and energy; and

•  fixed manufacturing costs, including operating and maintenance costs, principally staff costs, and depreciation and amortization of property, plant and equipment.

      Selling, general and administrative expenses. Selling, general and administrative expenses comprise selling and various general administrative expenses, including accounting, IT and corporate overhead costs, as well as related depreciation and amortization.

      Research and development expenses. Research and development expenses include costs related to activities focused on short-term performance improvements as well as expenses incurred to support the long-term growth of our business. All research and development costs are expensed as incurred.

      Restructuring and asset impairment charges. Restructuring costs relate to charges incurred in connection with restructuring our business to improve our performance. Asset impairment charges relate to charges incurred to reduce the carrying value of an asset to its fair value where we have determined that the asset’s carrying value is greater than the future cash flows expected to be derived from the asset.

      Interest expense. Interest expense primarily comprises interest charges on long-term debt related to the petrochemical facilities at our Grangemouth, United Kingdom site. The debt was repaid on March 22, 2005.

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      Other income (expense), net. Other income (expense), net primarily consists of non-trading income, foreign exchange gains and losses, gains and losses on the sale of assets and other miscellaneous items.

      Provision for income taxes for continuing operations. We record deferred tax assets to account for deductible temporary differences between the carrying amount of our assets and liabilities and our tax base for these assets and liabilities, unused tax losses and unused tax credits. In addition, we establish valuation allowances when we determine that there is significant uncertainty that we will be able to realize all or a portion of a deferred tax asset. In determining the need for establishing a valuation allowance, we consider many factors, including our expectations regarding our future taxable income in the period during which we expect the temporary differences to reverse and the loss carry-forward periods under the applicable tax laws, as well as our income tax strategies in the relevant jurisdictions. For periods prior to 2000, we have not identified the amount of deferred tax assets in respect of operating loss carry-forwards and tax credits due to the fact that this is a carve out situation and the number of assumptions that would be required to quantify such assets. Effectively, we have completely reserved these deferred tax assets. This accounting results in limiting the recognition of current period tax benefits after 2000 to the amount of any deferred tax expense incurred in such periods and the amount of net assets, if any, that is expected to be realizable in the future. Effective April 1, 2005, as a result of our separation from BP, our tax basis with respect to our assets changed. For periods after April 1, 2005, as a result of our formation as a separate legal entity within the BP group, we will fully account for deferred taxes, including the recognition of deferred tax assets in respect of operating loss carry-forwards.

      For periods ended prior to April 1, 2005, we recorded income tax expense as if we filed separate tax returns from BP, notwithstanding the fact that our operations were often included in consolidated tax returns filed by BP and most of the related taxes were paid by BP. Income taxes deemed to have been paid on our behalf by BP are shown in the parent net investment line of our combined balance sheets. Losses generated by our business prior to April 1, 2005 were available to, and were utilized by other members of the BP group in line with BP’s tax strategies. However, in accordance with recording income tax expense as if we filed separate returns, we evaluated our own tax loss position on a separate return basis. Accordingly, we recorded our tax losses as deferred tax assets in the period in which they arose and assessed our ability to realize the resulting deferred tax assets based on all facts and circumstances. As described above, due to our inability to quantify the amount of the deferred tax assets in respect of pre-2000 operating loss carry-forwards and tax credits, we have not recorded those deferred tax assets. This, and our inability to utilize losses across jurisdictions, contributed to effective tax rates considerably higher than statutory tax rates for periods prior to 2005. Our effective tax rate for the six months ended June 30, 2005, 31.5%, is more in line with our normal expectations. This rate reflects increased income from operations and the lack of certain permanent differences associated with foreign currency transactions and the fair value adjustments of the Solvay put liability that affected prior period effective tax rates.

      Effective April 1, 2005, we and BP entered into tax sharing agreements, which govern our respective rights and obligations with respect to taxes for any tax period ending on or before April 1, 2005, as well as for any tax period beginning after April 1, 2005.

      You should note that BP manages its tax position for the benefit of its entire portfolio of businesses, and its tax strategies are not necessarily identical with the tax strategies that we would have followed or will follow as a standalone entity. Accordingly, our future provision for income taxes for continuing operations is likely to be materially different from the amounts shown in our combined statements of operations. In particular, you should note that for nearly all jurisdictions in which we have material operations, we received our assets from BP in transactions providing us with a depreciable asset base equal to fair value. Therefore, during profitable periods, we expect our cash tax rate (current tax expense) to be less than the applicable statutory rate; the difference between the statutory rate and the cash tax rate will approximate our deferred tax charge.

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Six Months Ended June 30, 2005 Compared with Six Months Ended June 30, 2004

Consolidated

Revenues

      Revenues increased by 43%, from $7,791 million in the six months ended June 30, 2004 to $11,131 in the six months ended June 30, 2005. This increase primarily reflects higher sales prices as a result of higher raw material costs in a market environment characterized by a tighter relationship between supply and demand in both our petrochemical and refining businesses.

Gross margin

      Gross margin increased from $538 million in the six months ended June 30, 2004 to $1,255 million in the six months ended June 30, 2005. As a percentage of revenues, gross margin rose from 7% to 11%. This strong improvement primarily reflects a more favorable market environment in the six months ended June 30, 2005, which allowed us to increase the prices for our products at a greater rate than the increase in our feedstock costs. To a lesser extent, the improvement of our gross margin reflects benefits derived from our Accelerator program, as explained in greater detail in the discussion of our segment results.

Selling, general and administrative expenses

      Selling, general and administrative expenses totaled $341 million in both the six months ended June 30, 2004 and the six months ended June 30, 2005. Although the total level of selling, general and administrative expenses was similar in both periods, there are significant differences in their composition as we now operate as a standalone company. In 2004, prior to our separation from BP, selling, general and administrative expenses included the costs of our own business as well as significant costs allocated to us by BP because there were certain services provided by BP as well as certain corporate costs allocated to us. In 2005, we have been operating on a standalone basis and, accordingly, most of our selling, general and administrative expenses are incurred directly by us. Also, there were certain cost increases as a result of this standalone operation, including insurance and additional employee incentive compensation as a result of improved financial performance, each of which amounted to $18 million in 2004. These cost increases were offset by decreases resulting from the streamlining of business processes in connection with our separation from BP.

Research and development expenses

      Research and development expenses decreased by 20%, from $64 million in the first six months of 2004 to $51 million in 2005. In addition to the timing of research and development costs for certain projects, this decrease reflects the fact that our formation as a separate legal entity within the BP group and the integration of Solvay’s HDPE-related research projects in our own R&T program allowed us to rationalize our R&T activities with respect to polymers in North America and to integrate R&T teams in Europe that had previously worked separately.

Restructuring and asset impairment charges

      Restructuring and asset impairment charges increased from $5 million in the six months ended June 30, 2004 to $21 million in the six months ended June 30, 2005. Restructuring charges in the six months ended June 30, 2004 reflect carryover charges from earlier years related to various workforce reduction programs, whereas restructuring charges in the six months ended June 30, 2005 reflect charges associated with workforce reductions which were initiated in late 2004 in connection with the establishment of our company and continued into 2005. We incurred no asset impairment charges in either period.

Interest expense

      Interest expense remained flat at $25 million in the six months ended June 30, 2005 when compared with the same period in 2004, reflecting the fact that total debt levels remained at a similar level.

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Other income (expense), net

      Other income (expense), net decreased from income of $27 million in the six months ended June 30, 2004 to an expense of $42 million in the six months ended June 30, 2005. This decrease primarily reflects losses associated with the early repayment of the long-term debt secured by the petrochemical assets of our site in Grangemouth, United Kingdom, in the six months ended June 30, 2005. Another contributing factor was that in the six months ended June 30, 2004, the derivative contracts associated with this debt had generated gains of $13 million.

Provision for income taxes for continuing operations

      Provision for income taxes for continuing operations increased from $86 million in the six months ended June 30, 2004 to $233 million in the six months ended June 30, 2005, primarily reflecting an increase in income from continuing operations. Our effective tax rate for the six months ended June 30, 2005 was 31.5%. Our effective tax rate was impacted by increased earnings in jurisdictions with statutory tax rates lower than the U.S. federal tax rate and our inability to utilize some loss carry-forwards in non-U.S. jurisdictions. The effective tax rate for the six months ended June 30, 2004 is higher than the statutory tax rates due principally to our being unable to recognize losses from foreign currency transactions in certain jurisdictions and the non-deductibility of the change in fair value of the Solvay put liabilities and losses. In addition, our inability to recognize our deferred tax asset balances in respect of losses brought forward limited our recognition of tax benefits to the amount of deferred tax expense in loss-making jurisdictions.

Loss from discontinued operations, net of income tax expense (benefit)

      Loss from discontinued operations was $11 million in the six months ended June 30, 2004 and $3 million in the six months ended June 30, 2005. This improvement was due to lower depreciation because of the write-down of the book value of our BDO business at the end of 2004 and the sale of this business at the end of March 2005.

Net income

      Net income increased from $38 million in the six months ended June 30, 2004 to $543 million in the six months ended June 30, 2005, reflecting the factors discussed above.

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      The following table provides an overview of the historical revenues and adjusted EBITDA of each of our segments for the periods indicated:

		For the six months
		ended June 30,
		2004			2005
		(unaudited)
		($ in millions)
Revenues(1)
	O&P North America		1,615			2,150
	O&P Europe		3,328			4,399
	Global Derivatives		1,015			1,272
	Refining		2,699			4,331
	Corporate and Other		24			46
	Intersegmental eliminations		(890	)		(1,067	)
Total			7,791			11,131
Adjusted EBITDA(2)
	O&P North America		77			250
	O&P Europe		195			492
	Global Derivatives		41			164
	Refining		164			436
	Corporate and Other		(73	)		(254	)
Total			404			1,088

(1)	Revenues exclude revenues from discontinued operations. Revenues from discontinued operations for the six months ended June 30, 2004 and 2005 were $30 million and $11 million, respectively.
(2)	For more information on how we calculate adjusted EBITDA, see “Selected Combined Financial Data — Use of Non-GAAP Financial Measures.”

O&P North America

Revenues

      Revenues of our O&P North America segment increased by 32%, from $1,615 million in the six months ended June 30, 2004 to $2,150 million in the six months ended June 30, 2005. Revenues included intersegmental sales (primarily sales of ethylene and propylene to our Global Derivatives segment) of $241 million in the six months ended June 30, 2004 and $319 million in the six months ended June 30, 2005. The increased revenues are due primarily to higher sales prices, reflecting higher feedstock costs and tightening market conditions.

Adjusted EBITDA

      Adjusted EBITDA of our O&P North America segment increased substantially, from $77 million in the six months ended June 30, 2004 to $250 million in the six months ended June 30, 2005. The majority of this increase reflects increased margins for ethylene, polyethylene and polypropylene due to tightening supply and demand conditions and an unscheduled outage at a facility of one of our major ethylene competitors in the first three months of 2005. In addition, we started to benefit from our ongoing Accelerator program, including the renegotiation of our polyethylene and polypropylene customer contracts to include more responsive pricing provisions and lower fixed manufacturing and selling, general and administrative costs.

O&P Europe

Revenues

      Revenues of our O&P Europe segment increased by 33%, from $3,328 million in the six months ended June 30, 2004 to $4,399 million in the six months ended June 30, 2005. Revenues included intersegmental sales

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(primarily sales of ethylene and propylene to our Global Derivatives segment) of $275 million in the six months ended June 30, 2004 and $350 million in the six months ended June 30, 2005. The increase in revenues reflects the effect of higher sales prices as a result of higher feedstock costs and tightening market conditions.

Adjusted EBITDA

      Adjusted EBITDA of our O&P Europe segment increased from $195 million in the six months ended June 30, 2004 to $492 million in the six months ended June 30, 2005. The majority of this increase was caused by higher margins due to improved market conditions, which led to a more than proportionate increase in our sales prices compared with our feedstock costs.

      The increase in adjusted EBITDA was also driven by performance improvements as part of our Accelerator program. For example, we put in place new arrangements to import propane feedstock for the gas cracker at our site in Grangemouth, United Kingdom, to supplement the locally available feedstock and to improve utilization. Furthermore, we changed the catalyst of our ethylene oxide (EO) unit at our Lavéra, France, and Cologne, Germany sites, which resulted in better reliability and significant capacity improvements. In addition, we rationalized our LDPE product range at our Cologne, Germany, site, which reduced complexity and led to efficiency gains.

Global Derivatives

Revenues

      Revenues of our Global Derivatives segment increased by 25%, from $1,015 million in the six months ended June 30, 2004 to $1,272 million in the six months ended June 30, 2005. Increased sales prices resulted in a 21% increase in revenues, while higher sales volumes increased revenues by 4%. The increase in price was principally caused by improved market prices. The overall increase in volumes was mainly a result of strong demand for alpha olefins in polyethylene co-monomer and oilfield applications, the effect of which was partially offset by a decrease in acrylonitrile volumes.

Adjusted EBITDA

      Adjusted EBITDA of our Global Derivatives segment increased significantly from $41 million in the six months ended June 30, 2004 to $164 million in the six months ended June 30, 2005. The substantial rise in adjusted EBITDA was due for the most part to higher margins achieved in a stronger market environment. To a lesser extent, results also benefited from our Accelerator program efforts, including the renegotiation of customer contracts for both acrylonitrile and alpha olefins and more spot sales. The segment’s results also benefited from higher utilization rates due to the absence of turnarounds and lower fixed costs as a result of efficiency gains following the combination of two business units which were previously managed separately.

Refining

Revenues

      Revenues of our Refining segment increased by 61%, from $2,699 million in the six months ended June 30, 2004 to $4,331 million in the six months ended June 30, 2005. Revenues included intersegmental sales (primarily sales of naphtha to our O&P Europe segment) of $367 million in 2004 and $399 million in 2005. Increased selling prices resulted in a 55% increase in revenues. Sales volumes increased by 15,000 barrels per day in the first six months of 2005 relative to the first six months of 2004, resulting in a 5% increase in revenues.

Adjusted EBITDA

      Adjusted EBITDA of our Refining segment increased from $164 million in the six months ended June 30, 2004 to $436 million in the six months ended June 30, 2005. This increase reflects the fact that both refineries achieved higher cash margins on a per-unit basis. Cash margins in our refineries are calculated as gross margin without depreciation, per barrel of crude oil. The weighted average cash margin of our refineries increased by approximately $3.80 per barrel in the six months ended June 30, 2005 relative to the six months ended June 30,

41

2004. A significant factor contributing to this development were increases in inventory values. Inventory gains were $130 million in the six months ended June 30, 2005, compared to $45 million in the six months ended June 30, 2004. Our Lavéra refinery’s performance showed a particularly strong improvement because of its feedstock flexibility, which was particularly beneficial early in 2005. These higher margins were driven by a general improvement in the market environment and a widening light to heavy oil price differential. In the case of Grangemouth, margins benefited from a tightening supply and demand balance in the market for distillates.

Corporate and Other

Revenues

      Revenues of our Corporate and Other segment increased from $24 million in the six months ended June 30, 2004 to $46 million in the six months ended June 30, 2005, reflecting increased sales of acrylonitrile and polypropylene catalysts.

Adjusted EBITDA

      Adjusted EBITDA of our Corporate and Other segment decreased from a loss of $73 million in the six months ended June 30, 2004 to a loss of $254 million in the six months ended June 30, 2005. This increased loss reflects a number of factors, principally a loss of $45 million which we incurred as a result of the early repayment of the loans secured by the petrochemical assets of our site in Grangemouth, United Kingdom, which was partially offset by a gain of $3 million on derivative contracts associated with this debt. This compares with a derivative contract gain of $13 million in 2004. The increased loss also reflects approximately $80 million of additional costs for employee incentive compensation, reflecting the improved results of the business, costs of $20 million in the first six months of 2005 related to foreign currency options contracts put in place to manage some of our currency exposure and $18 million of costs related to our stand-alone insurance programs, which were put in place at the beginning of 2005 with BP’s captive insurance company. Previously we were part of BP’s self-insurance program.

Year Ended December 31, 2004 Compared with Year Ended December 31, 2003

Consolidated

Revenues

      Revenues increased by 34%, from $13,422 million in 2003 to $17,937 million in 2004, reflecting higher market prices for our products in both our petrochemical and our refining business.

Gross margin

      Gross margin increased by 40%, from $836 million in 2003 to $1,172 million in 2004. As a percentage of revenues, gross margin improved slightly from 6% to 7%. The improvement in gross margin was driven by increasingly favorable market conditions for refining and olefins products due to tight supply relative to strong demand, which increased our product prices in excess of the increase in feedstock costs. The effects of this improvement were partially offset by revenues lost to turnarounds at our sites in Grangemouth, United Kingdom, Cologne, Germany, and Lavéra, France, and the impact of the weakening of the U.S. dollar relative to the euro and the British pound, which resulted in higher fixed and variable manufacturing costs in Europe.

Selling, general and administrative expenses

      Selling, general and administrative expenses increased by 2%, from $616 million in 2003 to $630 million in 2004. The impact of the decline in the value of the U.S. dollar relative to the euro and the British pound resulted in higher costs. Costs also increased because of expenses in connection with our formation as a separate legal entity within the BP group and the establishment of our own corporate functions. These cost increases were partially offset by early benefits from the streamlining of business processes in connection with our separation from BP.

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Research and development expenses

      Research and development expenses increased by 19%, from $115 million in 2003 to $137 million in 2004. Activity levels across the two years were similar, with the main contributing factor being the weakening of the U.S. dollar relative to the euro and the British pound.

Restructuring and asset impairment charges

      In 2004, we incurred restructuring and impairment charges in the amount of $345 million relating to various events, including:

•  a $228 million charge related to the anticipated closure of the LAO facility in Pasadena, Texas, currently operated for us by BP under a toll manufacturing agreement, in late 2005, consisting of an impairment charge of $185 million and costs to close and decommission the facility in the amount of $42 million; and

•  a $69 million charge related to the closure of an HDPE line at our Grangemouth site; and

•  a $19 million write-down of assets related to our maleic catalyst business.

      In 2003, restructuring and asset impairment charges in the amount of $72 million included:

•  a $36 million charge related to write-off of alkylations and sulfur units located at our Grangemouth site, and of a part of the facility damaged by a fire;

•  a $20 million charge related to employee severance and transition costs at our Grangemouth site; and

•  an $11 million charge related to restructuring activities at our facilities in Geel, Belgium and Grangemouth and a reorganization of our alpha olefins businesses.

Interest expense

      Interest expense increased by 11%, from $44 million in 2003 to $49 million in 2004. This increase primarily reflects the weakness of the U.S. dollar relative to the British pound, leading to higher interest payments on the loans secured by the petrochemical assets of our site in Grangemouth.

Other income (expense), net

      Other income (expense), net improved from a loss of $123 million in 2003 to a loss of $24 million in 2004. This decrease in the loss was the result of $63 million of lower losses associated with the put liability under our former joint ventures with Solvay and approximately $29 million of gains associated with foreign exchange derivative contracts. These contracts were put in place to help manage certain foreign exchange exposures. As described in note 9 of our combined financial statements, this put liability arose due to a put instrument held by Solvay giving Solvay the right to require us to purchase its interests in the joint ventures at certain dates and prices. Solvay exercised this right on November 2, 2004.

Provision for income taxes for continuing operations

      Provision for income taxes for continuing operations increased, from $90 million in 2003 to $128 million in 2004. Our effective tax rates for 2003 and 2004 were higher than the statutory tax rates due principally to our inability to recognize losses from foreign currency transactions in certain jurisdictions and the non-deductibility of the change in fair value of the Solvay put liabilities and losses. In addition, our inability to recognize deferred tax asset balances in respect of losses brought forward limited the amount of tax benefits we were able to recognize to the amount of deferred tax expense in loss-making jurisdictions. The provision for income taxes for continuing operations in 2004 increased from 2003 in line with a lower loss from continuing operations before income taxes.

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Loss from discontinued operations, net of income tax expense (benefit)

      Loss from discontinued operations, net of income tax expense (benefit), increased from $25 million in 2003 to $128 million in 2004. This increase was caused primarily by an asset impairment charge of $148 million (before tax) in 2004, which related to the write-down of assets associated with our BDO business prior to its disposal in March 2005.

Net loss

      Net loss increased from $240 million in 2003 to $261 million in 2004, reflecting the factors described above.

      The following table provides an overview of the historical revenues and adjusted EBITDA of each of our segments for the periods indicated:

		For the year
		ended
		December 31,
		2003			2004
		($ in millions)
Revenues(1)
	O&P North America		2,698			3,680
	O&P Europe		5,609			7,424
	Global Derivatives		1,769			2,090
	Refining		4,779			6,555
	Corporate and Other		69			97
	Intersegmental eliminations		(1,502	)		(1,909	)
Total			13,422			17,937
Adjusted EBITDA(2)
	O&P North America		171			257
	O&P Europe		54			334
	Global Derivatives		74			5
	Refining		199			410
	Corporate and Other		(26	)		(137	)
Total			472			869

(1)	Revenues exclude revenues from discontinued operations. Revenues from discontinued operations for the year ended December 31, 2003 and 2004 were $52 million and $59 million, respectively.
(2)	For more information on how we calculate adjusted EBITDA, see “Selected Combined Financial Data — Use of Non-GAAP Financial Measures.”

O&P North America

Revenues

      Revenues of our O&P North America segment increased by 36%, from $2,698 million in 2003 to $3,680 million in 2004. Revenues included intersegmental sales of $389 million in 2003 and $500 million in 2004. The increase in intersegmental sales was due to increased prices, the effect of which was partially offset by decreased volumes. The increase in total revenues primarily reflected higher market prices across all products as a result of higher feedstock prices.

Adjusted EBITDA

      Adjusted EBITDA of our O&P North America segment increased by $86 million, or 50%, from $171 million in 2003 to $257 million in 2004. Higher margins for our olefins products due to favorable market conditions were partially offset by lower margins for polymer products. The segment’s adjusted EBITDA also benefited from lower fixed manufacturing costs, primarily as a result of the fact that there were no turnarounds at

44

our site in Chocolate Bayou, Texas in 2004. Another factor contributing to the improved adjusted EBITDA figure was the first full year of operations of our HDPE joint venture with Chevron Phillips.

O&P Europe

Revenues

      Revenues of our O&P Europe segment increased by 32%, from $5,609 million in 2003 to $7,424 million in 2004. Revenues included intersegmental sales of $500 million in 2003 and $550 million in 2004. The overall increase in revenues primarily reflects higher sales prices as a result of higher raw material costs, which increased revenues by $1,385 million. The remainder of the increase reflects the impact of higher sales volumes.

Adjusted EBITDA

      Adjusted EBITDA of our O&P Europe segment increased from $54 million in 2003 to $334 million in 2004. The increase in adjusted EBITDA primarily reflects the fact that we were able to achieve higher unit margins due to favorable market conditions. In the first half of 2004, we were not always able to pass on increases in our feedstock costs to our customers, who were under pressure due to lower economic growth rates in Europe and mounting competitive pressures from imports as the euro and the British pound continued to strengthen against the U.S. dollar. In the second half, feedstock costs peaked and product markets tightened allowing us to raise our product prices and achieve higher margins.

      Reliability issues at the derivatives units at our site in Grangemouth, United Kingdom in the first half of 2004 resulted in reduced utilization of these units. In the second half of the year, reliability improved as we took steps to address these issues. The improvement in reliability enabled us to take advantage of market opportunities, following a series of unplanned shutdowns of our competitors’ crackers. In addition, we started to benefit from more responsive pricing provisions in our customer contracts. Further benefits resulted from the elimination of certain product grades in our LDPE business and efficiency gains realized in our polypropylene business. The effect of these factors was partially offset by higher levels of fixed manufacturing costs and selling, general and administrative expenses due to increased turnaround activity and the continued weakening of the U.S. dollar relative to the euro and the British pound.

      Another factor contributing to the higher adjusted EBITDA figure was the fact that we incurred lower losses associated with the joint venture put liability under our former joint ventures with Solvay. Losses associated with the European joint venture were $99 million in 2004 compared to $120 million in 2003.

Global Derivatives

Revenues

      Revenues of our Global Derivatives segment increased by 18%, from $1,769 million in 2003 to $2,090 million in 2004. This increase reflects a 23% increase due to higher prices and a 5% decrease in volumes. The price increases were driven by acrylonitrile and, to a lesser extent, LAOs and PAOs. Acrylonitrile prices received a boost from record propylene prices. Acrylonitrile volumes declined as a result of price increases and scheduled turnarounds at our Lima, Ohio facility and from the larger acrylonitrile unit at our site in Cologne, Germany. LAO and PAO revenues were driven by increased prices and volumes, reflecting improved market conditions. This improvement was partially offset by weaker volumes of the heavier LAOs.

Adjusted EBITDA

      Adjusted EBITDA of our Global Derivatives segment decreased from $74 million in 2003 to $5 million in 2004. This decrease was due primarily to restructuring costs incurred in connection with our decision to cease production at the Pasadena, Texas, facility which is operated for us by BP under a toll manufacturing agreement, due to overcapacity in the LAO industry, the age of the facility, its product mix/quality and its relatively high fixed costs. Adjusted EBITDA was also negatively impacted by operational problems at the ammonia unit of our site in Cologne, Germany, which led to higher manufacturing costs and lower efficiency at that facility. We addressed these issues in connection with a scheduled turnaround at that facility in the second half of the year.

45

Further reductions of adjusted EBITDA resulted from the continued weakening of the U.S. dollar relative to the euro. These factors more than offset margin improvements for our acrylonitrile, LAO and PAO product lines, due to increasingly favorable market conditions.

Refining

Revenues

      Revenues of our Refining segment increased by 37%, from $4,779 million in 2003 to $6,555 million in 2004. Revenues included intersegmental sales of $613 million in 2003 and $859 million in 2004. The overall increase in revenues was driven by higher sales prices, especially for diesel and gasoline. Volumes were slightly lower in 2004 as a result of a major turnaround at Lavéra, and these lower overall volumes reduced revenues by $35 million.

Adjusted EBITDA

      Adjusted EBITDA of our Refining segment increased from $199 million in 2003 to $410 million in 2004. Both refineries contributed to this increase, reflecting significantly higher cash margins per barrel, as improved sales prices outpaced rising feedstock costs due to favorable market conditions as a result of strong global demand for refined products, low industry inventory levels and high refinery utilization. The weighted average cash margin of our refineries increased by approximately $1.65 per barrel in 2004 relative to 2003. The effect of these factors was partially offset by higher fixed manufacturing costs resulting from a turnaround at the Lavéra refinery, higher maintenance charges, pension costs and expenses incurred at the Grangemouth refinery in preparation for recommissioning the refinery’s FCC. Another offsetting factor was the continued weakening of the U.S. dollar against the euro and the British pound.

Corporate and Other

Revenues

      Revenues of our Corporate and Other segment increased from $69 million in 2003 to $97 million in 2004, primarily reflecting increased polymer catalyst sales.

Adjusted EBITDA

      Adjusted EBITDA of our Corporate and Other segment decreased from a loss of $26 million in 2003 to a loss of $137 million in 2004. This increased loss reflects several factors, including an increase in the provision for intercompany profit in inventory of $37 million and a net charge of $15 million due to the effect of the weaker U.S. dollar relative to the British pound on the loans secured by the petrochemical assets of our site in Grangemouth, United Kingdom, and derivative contracts associated with this debt. Property management and separation costs contributed a further $14 million and $8 million, respectively, to the increase in the loss.

Year Ended December 31, 2003 Compared with Year Ended December 31, 2002

Consolidated

Revenues

      Revenues increased by 14%, from $11,776 million in 2002 to $13,422 million in 2003. This increase was driven by higher sales prices in both our petrochemical and our refining businesses.

Gross margin

      Gross margin decreased by 17%, from $1,001 million in 2002 to $836 million in 2003. As a percentage of revenues, gross margin declined from 9% to 6%. The decrease in gross margin in both absolute and relative terms reflects an increase in fixed manufacturing costs and higher levels of depreciation. The rise in fixed manufacturing costs was caused by turnarounds at our Chocolate Bayou, Texas, Grangemouth, United Kingdom and Cologne, Germany facilities. In addition, both fixed manufacturing costs and depreciation went up as a result

46

of the weakening of the U.S. dollar against the euro and the British pound. The effect of these factors was partially offset by more favorable market conditions for olefins and refining products, which allowed us to increase our product prices in excess of the increase in our feedstock costs.

Selling, general and administrative expenses

      Selling, general and administrative expenses decreased by 16%, from $734 million in 2002 to $616 million in 2003. The decrease in selling, general and administrative expenses was due primarily to cost reduction programs, particularly in the administrative functions of our businesses and in our corporate area.

Research and development expenses

      Research and development expenses decreased by 4%, from $120 million in 2002 to $115 million in 2003, reflecting consolidation of our research facilities in Europe. The effect of this decrease was partially offset by weakening of the U.S. dollar relative to the euro and the British pound.

Restructuring and asset impairment charges

      In 2003, we incurred restructuring and impairment charges in the amount of $72 million relating to various events, including:

•  a $36 million charge related to the write-off of the alkylation and sulfur units located at our Grangemouth, United Kingdom, site, as well as a part of the facility damaged by a fire;

•  a $20 million charge related to employee severance and transition costs at our Grangemouth site; and

•  an $11 million charge related to restructuring activities at our facilities in Geel, Belgium and Grangemouth, and a reorganization of our alpha olefins businesses.

      In 2002, restructuring and asset impairment charges in the amount of $93 million included:

•  a $32 million charge primarily related to employee severance and asset impairments in connection with the polypropylene business we acquired from Solvay in 2001 and our former joint ventures with Solvay;

•  a $21 million charge related to the restructuring of our technology function, consisting of employee severance and relocation costs as well as asset impairments;

•  a $20 million charge related to the closure of a polypropylene line at our site in Chocolate Bayou;

•  a $12 million charge related to asset impairments recorded in connection with a redundant pipeline at our Grangemouth, site; and

•  an $8 million charge related to various other activities, including restructuring activities at our site in Lavéra, France.

Interest expense

      Interest expense increased by 26%, from $35 million in 2002 to $44 million in 2003. This increase reflects the strengthening of the British pound relative to the U.S. dollar and the resulting impact on the interest payments on the loans secured by the petrochemical assets of our Grangemouth, United Kingdom, site.

Other income (expense), net

      Other income (expense), net increased from an expense of $65 million in 2002 to an expense of $123 million in 2003. This change primarily reflects:

•  a gain of $25 million related to the disposal of a partial interest in the Aethylen Rohrleitungs Gesellschaft mbH & Co. KG (ARG) pipeline in 2002, compared with a loss of $7 million related to an adjustment in the level of the gain on this disposal in 2003;

47

•  the expense related to the change in value of put liabilities related to our former joint ventures with Solvay increased from $128 million in 2002 to $168 million in 2003; and

•  the remaining change is due to gains associated with foreign exchange derivatives in 2003.

Provision for income taxes for continuing operations

      Provision for income taxes for continuing operations decreased from $118 million in 2002 to $90 million in 2003. This decrease was due to an increase in our loss from continuing operations before income taxes. In each of 2002 and 2003, our effective tax rate exceeded the statutory tax rate due principally to our inability to recognize losses from foreign currency transactions in certain jurisdictions and the non-deductibility of the change in fair value of put liabilities and losses related to our former joint ventures with Solvay. In addition, our inability to recognize deferred tax asset balances in respect of losses brought forward limited the amount of tax benefits we were able to recognize to the amount of deferred tax expense in loss-making jurisdictions.

Loss from discontinued operations, net of income tax expense (benefit)

      Loss from discontinued operations decreased by 14%, from $29 million in 2002 to $25 million in 2003, but the continued losses reflect the difficult business environment of the BDO unit of our Lima, Ohio facility, which we sold in March 2005.

Net loss

      Net loss increased from $195 million in 2002 to $240 million in 2003, reflecting the effect of the factors described above.

      The following table provides an overview of the historical revenues and adjusted EBITDA of each of our segments for the periods indicated:

		For the year ended
		December 31,
		2002			2003
		($ in millions)
Revenues(1)
	O&P North America		2,341			2,698
	O&P Europe		4,863			5,609
	Global Derivatives		1,749			1,769
	Refining		3,876			4,779
	Corporate and Other		112			69
	Intersegmental eliminations		(1,165	)		(1,502	)
Total			11,776			13,422
Adjusted EBITDA(2)
	O&P North America		91			171
	O&P Europe		148			54
	Global Derivatives		211			74
	Refining		44			199
	Corporate and Other		(52	)		(26	)
Total			442			472

(1)	Revenues exclude revenues from discontinued operations. Revenues from discontinued operations for the year ended December 31, 2002 and 2003 were $39 million and $52 million, respectively.
(2)	For more information on how we calculate adjusted EBITDA, see “Selected Combined Financial Data — Use of Non-GAAP Financial Measures.”

48

O&P North America

Revenues

      Revenues of our O&P North America segment increased by 15%, from $2,341 million in 2002 to $2,698 million in 2003. Revenues included intersegmental sales of $301 million in 2002 and $389 million in 2003. The increase in revenues was due mainly to an increase in average sales prices. In addition, the consolidation of our facility in Carson, California, following the acquisition of our joint venture partner’s share in 2003, contributed $86 million to revenues.

Adjusted EBITDA

      Adjusted EBITDA of our O&P North America segment increased from $91 million in 2002 to $171 million in 2003. This increase was mainly driven by polypropylene, resulting from a beneficial time lag in our contracts with customers that allowed us to achieve higher polypropylene prices in the second half of 2003 at a time when the price for propylene was declining. Higher ethylene margins were offset by lower volumes and a rise in fixed costs due to a turnaround of the crackers at our Chocolate Bayou, Texas site. In addition, the growth of adjusted EBITDA reflects the fact that we purchased ethylene from another manufacturer at a time when gas prices temporarily spiked relative to feedstocks whose prices are linked to crude oil prices, enabling us to purchase ethylene at a lower cost than we would have had to incur had we produced it internally based on gas.

O&P Europe

Revenues

      Revenues of our O&P Europe segment increased by 15%, from $4,863 million in 2002 to $5,609 million in 2003. Revenues included intersegmental sales of $400 million in 2002 and $500 million in 2003. The overall increase in revenues was due to higher selling prices, which increased revenues by $357 million with the remainder due to higher sales volumes. For the most part, the increase in sales volumes was driven by olefins and polyethylene. The main contributing factors were higher cracker utilization rates and the commencement of operations of the expanded cracker at our Cologne, Germany site, which increased our ethylene capacity at that site by around 10%. Volumes also benefited from the first full-year contribution of our new HDPE production unit at our Lillo, Belgium, facility which had been commissioned in the second half of 2002. However, the effect of this addition was partially offset by competitive pressures in the polyethylene markets due to increased competition from commodity producers with manufacturing operations in the Middle East, which limited our volume growth.

Adjusted EBITDA

      Adjusted EBITDA of our O&P Europe segment decreased by 64%, from $148 million in 2002 to $54 million in 2003. This decrease was driven by continued pressure on our margins, which were squeezed by increasing feedstock prices and our inability to pass on these increases to our customers due to a lack of market growth. The pressure was particularly strong in the polyethylene markets, which were characterized by intense competition from Middle East commodity imports. In addition, manufacturing, distribution and overhead costs increased in U.S. dollar terms due to the weakening of the U.S. dollar relative to the euro and the British pound. Also contributing to the decrease in adjusted EBITDA were higher expenses of $42 million related to the change in the value of the put liability in relation to our former joint ventures with Solvay. Expense related to the change in value of this obligation was $120 million in 2002 compared to $162 million in 2003. In addition, 2002 included a $25 million gain on the disposal of a partial interest in the ARG pipeline whereas 2003 reflected a loss of $7 million because of an adjustment of the gain on this disposal.

Global Derivatives

Revenues

      Revenues of our Global Derivatives segment increased by 1%, from $1,749 million in 2002 to $1,769 million in 2003. The slight increase in revenues was driven by a 4% increase in prices, which was offset by a

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4% decrease in volumes. In both cases, the development was primarily driven by acrylonitrile and, to a lesser extent, LAOs and PAOs. In the case of acrylonitrile, the decline in volumes was caused by scheduled turnarounds, whereas in the case of LAOs and PAOs the decline reflects our attempt to preserve prices by cutting volumes.

Adjusted EBITDA

      Adjusted EBITDA of our Global Derivatives segment decreased by 65%, from $211 million in 2002 to $74 million in 2003, driven by acrylonitrile, LAOs and PAOs. The decrease in adjusted EBITDA for acrylonitrile and LAOs and PAOs was due primarily to higher feedstock and energy costs, which rose faster than we were able to raise our sales prices. LAO margins also suffered from industry overcapacity, which put additional pressure on our margins. Adjusted EBITDA also suffered from turnarounds at our Green Lake, Texas, and Cologne, Germany, facilities and reliability issues at the ammonia unit of our Cologne facility, which forced us to purchase ammonia on the market, leading to an increase in feedstock costs and higher maintenance expenses. The weakening of the U.S. dollar relative to the euro and the British pound further contributed to the decline in adjusted EBITDA. The effect of these factors was partially offset by headcount reductions in our alpha olefins business in connection with a restructuring of that business.

Refining

Revenues

      Revenues of our Refining segment increased by 23%, from $3,876 million in 2002 to $4,779 million in 2003. Revenues included intersegmental sales of $465 million in 2002 and $613 million in 2003. The overall increase in revenues was driven by higher prices, while volumes were 4% lower than in 2002 as a result of a turnaround at our Grangemouth, United Kingdom facility. Revenues increased for both refineries across all products, with diesel, gasoline and naphtha experiencing the strongest increases.

Adjusted EBITDA

      Adjusted EBITDA of our Refining segment increased from $44 million in 2002 to $199 million for 2003, reflecting improved cash margins at both our refineries. The weighted average cash margin of our refineries increased by approximately $1.20 per barrel in 2003 relative to 2002. This development was driven by more favorable market conditions, the effects of which were partially offset by the continued weakening of the U.S. dollar against the euro and the British pound.

Corporate and Other

Revenues

      Revenues of our Corporate and Other segment decreased by 38%, from $112 million in 2002 to $69 million in 2003. This decrease reflects a decline in licensing revenues, as 2002 included revenues from certain major projects which were not repeated in 2003.

Adjusted EBITDA

      EBITDA of our Corporate and Other segment increased from a loss of $52 million in 2002 to a loss of $26 million in 2003. This reduction reflects lower administration expenses and gains associated with foreign exchange derivatives contracts.

Liquidity and Capital Resources

      The primary source of liquidity for our business is cash generated from operations. In periods during which we experienced shortfalls in cash generated from operations, BP has historically provided us with additional funds. In the past, we primarily used cash for capital expenditures, working capital and pension contributions. Over the next several years, we expect to use a portion of our cash reserves to service debt.

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      We believe we will have sufficient cash to meet both our short-term and long-term liquidity requirements, including our debt service requirements. If our cash flow from operations is insufficient to fund our debt service and other obligations, we may need to raise funds using other means available to us, such as increasing our borrowings, decreasing or delaying capital expenditures, accelerating improvements in working capital management, making divestitures, raising additional capital or restructuring or refinancing our indebtedness. However, there can be no assurance that such funds would be available on commercially reasonable terms or at all.

Cash Flows

Net Cash Provided by Operating Activities of Continuing Operations

      Cash flow from operating activities of continuing operations increased by $251 million, from $513 million in the six months ended June 30, 2004 to $764 million for the six months ended June 30, 2005. This increase primarily reflects improved operating results, mainly as a result of a better margin environment for all of our businesses in the six months ended June 30, 2005.

      Net cash provided by operating activities from continuing operations was $177 million, $695 million, and $383 million for each of 2002, 2003 and 2004, respectively. The primary reason for the significant changes in net cash provided by operating activities was changes in our working capital and other operating assets and liabilities. Our working capital balances typically develop in line with feedstock prices, although timing factors can affect flows of capital in any individual year. Over the three years, operating working capital and other operating assets and liabilities increased by $934 million, reflecting the impact of higher oil and gas prices on inventories and higher product prices, which increased our net accounts receivable. In 2002, we experienced a cash outflow in the amount of $411 million associated with working capital and other operating assets and liabilities. In 2004, this outflow amounted to $545 million. In both cases, the outflow was caused by increasing feedstock prices. The cash impact in 2003 was not as significant because of lower inventory levels, offsetting some of the effect of higher prices.

Net Cash Used in Investing Activities of Continuing Operations

      Net cash used in investing activities of continuing operations increased from $218 million in the six months ended June 30, 2004 to $250 million in the six months ended June 30, 2005, reflecting higher levels of capital expenditure.

      Net cash used in investing activities of continuing operations was $579 million, $561 million and $565 million for each of 2002, 2003 and 2004, respectively. The consistent level of cash requirements for investing activities reflects the steady level of capital investment over the three-year period.

Net Cash Provided by (Used in) Financing Activities of Continuing Operations

      Net cash used in financing activities of continuing operations increased from $260 million in the six months ended June 30, 2004 to $559 million in the six months ended June 30, 2005. In both periods, our net cash provided by operating activities was transferred to BP, thereby reducing owner’s equity. The increase in cash available to BP reflects the improvement in net cash provided by operating activities. We repaid the debt that was secured by our Grangemouth, United Kingdom petrochemical assets on March 22, 2005. The repayment was financed through a loan granted by BP, which matures on March 30, 2006, unless repaid earlier.

      Net cash provided by (used in) financing activities of continuing operations was $422 million, $(140) million and $203 million in 2002, 2003 and 2004, respectively. During 2004, we acquired the outstanding minority interests in our former joint ventures with Solvay in Europe and North America, which required an expenditure of $1,538 million. This expenditure was funded by BP through an increase in owner’s equity. Our 2003 cash flow from financing activities reflects the excess of operating cash over cash required for our investing activities. In 2002, we issued $290 million of additional debt and made cash calls of $100 million in the Solvay joint ventures in order to fund the joint ventures.

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Working Capital

      Historically, BP has used a worldwide, centralized approach to cash management. Cash accounts were reduced to zero on a daily basis and the financing of our operations and all related activity between our company and BP was reflected as business equity transactions in the parent net investment line of our combined balance sheets.

      Similarly, following the completion of the offering, we will adopt a centralized approach to cash management. Short-term fluctuations in our cash requirements will be funded by short-term investments, through issuances of commercial paper or through drawdowns on our revolving credit agreements.

Debt

Debt Due to BP

      As of April 1, 2005, we had $1,700 million of intercompany debt outstanding to BP under an intra-group loan facility. The interest rate on the loan is LIBOR plus five basis points, with interest payable every three months. LIBOR has been calculated based on the April 1, 2005 three-month LIBOR rate, which was 3.12%. This loan replaced the debt secured by the petrochemical assets of our site in Grangemouth, United Kingdom, described below under “— Other Long-term Debt”, which was repaid on March 22, 2005. The loan we have been granted by BP matures on March 30, 2006, unless repaid earlier. The annual impact of an increase or decrease of ten basis points in the interest rate on the loan would decrease or increase our pre-tax income by $1.7 million. We are currently in discussions with banks for term loans and other short-term facilities with which we intend to replace this loan. Accordingly, our interest expense may be higher or lower, depending on the maturity and interest rate of the bank financing we plan to obtain, the timing of repayment of the loan and the then-applicable LIBOR rate.

Other Long-Term Debt

      Our combined balance sheets included long-term debt of $1,585 million and $1,729 million at December 31, 2003, and 2004, respectively, related to loans secured by the petrochemical assets of our Grangemouth, United Kingdom site.

      The loans had terms of between 20 and 30 years and would have matured between 2018 to 2022. The average interest rate was 3.14%, 3.16% and 3.58% for the years ended December 31, 2002, 2003 and 2004, respectively, and we incurred interest charges of $37 million, $45 million and $58 million in 2002, 2003 and 2004, respectively.

      In connection with our separation from BP, the loans were repaid on March 22, 2005. The termination payment was $1,755 million, which exceeded the book value of the loans and resulted in a loss of $45 million, which is included in other income (expense), net.

Post-Employment Benefit Obligations

      Certain of our employees participate in benefit plans sponsored by us. These “standalone” plans, most of which are unfunded, were generally transferred from BP to us on April 1, 2005. At March 31, 2005, our actuarially-determined projected benefit obligations under these plans was $367 million.

      Our employees also participate in benefit plans sponsored by BP. Our employees will continue to participate in these plans until BP’s investment in our company falls below certain thresholds, generally 80% for U.S. group-wide plans and 50% for all other plans. During the participation period, we are generally required to reimburse BP for service costs incurred by it in administering these plans to the extent these costs relate to our employees.

      When BP’s investment in our company falls below certain thresholds, the net assets and benefit obligations of the relevant group-wide plans, to the extent they relate to our employees, will be assumed by separate standalone plans established by us. At December 31, 2004, it was estimated that the aggregate amount of benefit obligations that would transfer to us was $250 million if BP’s investment in our company fell below 80%, and $615 million if BP’s investment in our company fell below 50%. If the net assets transferred to us differ from the

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actuarially-determined benefit obligations, we or BP, as the case may be, will make a balancing payment to compensate the other party for the difference. We intend to contribute any balancing payments we may receive from BP to the relevant plans, subject to local laws and other considerations.

      Based on actuarial valuations, at December 31, 2004, our annualized pension and other post-retirement benefit expenses for group-wide and standalone plans was estimated to be between $100 million and $120 million. Based on the projected level of funding, our initial annual funding requirements for these plans were estimated to be $20 million to $30 million lower than this pension and post-retirement benefit expense. We will fund our plans in accordance with applicable local regulations and practice, and will provide additional funding as management deems appropriate from time to time.

Capital Expenditures

      Total capital expenditures for the six months ended June 30, 2005 were $250 million, primarily reflecting capital expenditures of $43 million related to the Distinctive Compliance Project (DCP) at our site in Chocolate Bayou, Texas, which was initiated in 2002 to meet new environmental laws and regulations, expand the facility’s ethylene capacity and improve process efficiency. With the exception of the DCP, there were no individually significant projects in the period. The remainder of the expenditure was primarily for HSSE projects and normal sustaining capital expenditures at our sites in addition to certain expenditures relating to our establishment as a standalone operation.

      Total capital expenditures for 2005 are expected to be slightly less than in 2004.

      Our capital expenditures were $567 million for the year ended December 31, 2004, reflecting capital expenditures of:

•  $129 million related to the DCP at the Chocolate Bayou site;

•  $83 million related to the replacement of the reformer tubes in the ammonia plant and the first phase of an expansion to de-bottleneck the acrylonitrile plant of our Cologne, Germany site; and

•  $48 million related to the FCC rebuild at our refinery in Grangemouth, United Kingdom.

      Our capital expenditures were $556 million for the year ended December 31, 2003, reflecting capital expenditures of:

•  $97 million related to the DCP at the Chocolate Bayou site;

•  $48 million related to various projects at the Cologne site; and

•  $32 million related to the FCC rebuild at the Grangemouth refinery.

      Our capital expenditures were $614 million for the year ended December 31, 2002, primarily reflecting capital expenditures of:

•  $57 million related to the DCP at the Chocolate Bayou site;

•  $49 million related to the closure of the alcohols production line and reconfiguration of the LAO unit of the Pasadena, Texas, facility, which is operated for us by BP under a toll manufacturing agreement;

•  $49 million related to the construction of an HDPE plant in Lillo, Belgium;

•  $36 million related to the construction of the Cedar Bayou, Texas, facility, which is operated by Chevron Phillips in a 50/50 joint venture between us and Chevron Phillips; and

•  $26 million related to an expansion of the cracker of the Cologne site to enable it to recycle ethane by-products.

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      The following table provides a breakdown of our capital expenditures by segments for the periods indicated:

							For the
							six months
	For the year ended						ended
	December 31,						June 30,
	2002		2003		2004		2004		2005
	($ in millions)
O&P North America		153		174		191		79		78
O&P Europe		261		209		164		72		103
Global Derivatives		88		45		66		22		9
Refining		58		110		117		45		23
Corporate and Other		54		18		29		—		37
Total		614		556		567		218		250

      We incurred $96 million, $151 million, $172 million and $54 million in HSSE-related capital expenditures for 2002, 2003, and 2004 and for the six months ended June 30, 2005, respectively. We expect to incur an estimated $140 million of such expenditures for the remainder of 2005. Although we cannot predict with certainty future capital expenditures, from 2005 to 2010 we expect to incur an estimated total of $830 million in HSSE-related capital expenditures, which includes $660 million in capital expenditures to comply with various regulations related to health, safety, security and the environment and an additional $170 million to meet industry good practice and internal safety standards. An estimated $490 million of this estimated total is expected to be made specifically to comply with various environmental regulations, which include an estimated $350 million related to compliance with the EU directive on integrated pollution prevention and control (IPPC). We anticipate that HSSE regulations will continue to require us and the industry in general to make capital expenditures. Since capital expenditures vary with applicable HSSE legal requirements, we cannot assure you that our recent capital expenditures are indicative of the amounts we may be required to spend to comply with future HSSE legal requirements.

Contractual Obligations

      While we own most of our major facilities, we lease certain office, factory and warehouse space and land, as well as data processing and other equipment, principally under non-cancelable operating leases.

      The following table provides a maturity analysis of our material contractual obligations as of December 31, 2004:

	Payments due by period
			Less than						More than
	Total		1 year		1-3 years		3-5 years		5 years
	($ in millions)
Contractual obligations
Long-term debt obligations		1,729		—		—		—		1,729
Capital lease obligations		21		2		4		4		11
Operating lease obligations		547		73		89		81		304
Unconditional purchase obligations		5,687		2,223		1,921		825		718
Other long-term liabilities reflected on Innovene’s balance sheet		528		30		65		70		363
Total		8,512		2,328		2,079		980		3,125

      The unconditional purchase obligations shown in the table primarily include arrangements to secure long-term access to supplies of feedstock which are used in our facilities in the ordinary course of business.

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      Other long-term liabilities are liabilities for pensions and other post-employment benefits. BP has agreed to retain approximately $262 million of obligations associated with retired employees participating in our German pension and post-employment benefit plans.

Off-Balance Sheet Arrangements

      We use various customary off-balance sheet arrangements, such as operating leases, to finance our business. None of these arrangements has or is likely to have a material effect on our results of operations, financial condition or liquidity.

Quantitative and Qualitative Disclosures about Market Risk

      We are exposed to various types of market risk, including changes in interest rates, currency exchange rates and the prices of certain commodities. In the case of commodities, this exposure arises from movements in the prices of the feedstocks we require to make our products. To manage this exposure, we generally acquire raw materials and sell finished products at posted or market-related prices, which are typically set on a quarterly, monthly or more frequent basis in line with industry practice. We seek to minimize reductions in our margins by passing through feedstock cost increases to our customers through higher prices for our products. In the three years ended December 31, 2004, we were not engaged in commodity or financial transactions that would have created additional or different exposures than those described above.

      Our cash flows and earnings are subject to exchange rate fluctuations. In our Refining segment, the prices of finished products and of the underlying raw materials are primarily denominated in U.S. dollars, whereas our other costs are largely denominated in euros and British pounds. In our European petrochemical business, product prices, certain feedstock costs and most other costs are denominated in euros and British pounds. From time to time, we may enter into foreign currency exchange instruments to minimize the short-term impact of movements in foreign exchange rates. On February 24, 2005, we entered into a transaction with BP to purchase options at a cost of $20 million. The exercise dates of these options are spread equally over eleven months from February 2005 to December 2005 and each gives the company the right to purchase an amount of $83 million at an exchange rate of $1.35/euro and an amount of $42 million at an exchange rate of $1.90/British pound. The options are reflected in our unaudited summary combined financial data on a mark-to-market basis. We recorded realized and unrealized losses in connection with these options of approximately $20 million through June 30, 2005.

      As of April 1, 2005, we had $1,700 million of intercompany debt outstanding to BP under an intra-group loan facility. The loans under this facility accrue interest at a rate of LIBOR plus five basis points, with interest payable every three months and will mature on March 30, 2006, unless repaid earlier. This facility replaced debt secured by the petrochemical assets of our site in Grangemouth, United Kingdom, which was repaid on March 22, 2005. A quarter percentage point increase or decrease in the interest rates on the total borrowings is estimated to change pre-tax income by approximately $4 million. In connection with the offering, our capital structure is expected to change. This change will change our exposure to interest rate risk. See “Capitalization” for more information on our capital structure.

Critical Accounting Policies

      The preparation of financial statements and related disclosures in accordance with accounting principles generally accepted in the United States requires our management to make judgments, assumptions and estimates that affect the amounts reported in our combined financial statements and the accompanying notes. Our management bases its estimates and judgments on historical experience, current economic and industry conditions and on various other factors that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. If actual results differ significantly from management’s estimates, there could be a material adverse effect on our results of operations, financial condition and liquidity.

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      Our significant accounting policies are summarized in note 3 to our combined financial statements. Summarized below are those of our accounting policies where the nature of the estimates or assumptions involved is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change and the impact of the estimates and assumptions on financial condition or results of operations is material.

Revenue Recognition

      We generate substantially all of our revenues through sales of products in the open market. We recognize revenue when it has been earned. Revenue for product sales is recognized when risk and title to the product transfer to the customer, collectibility is reasonably assured and pricing is fixed or determinable. Generally, revenue is recognized at the time of shipment or delivery of a product, depending on contractual terms. Revenue is recognized net of discounts and other price adjustments.

Inventory Valuation

      Our inventories are valued at the lower of cost or market value. Elements of cost in inventories include raw materials, direct labor, and manufacturing overhead. The majority of our inventories in the United States are valued at cost using the “last-in, first-out” method (LIFO). The balance of our inventories are valued using the “first-in, first-out” method (FIFO). Management adjusts the carrying value of U.S. inventories using a LIFO reserve account, requiring estimates of the impact of inflation on existing LIFO inventory pools as of each reporting date. LIFO inventories comprise approximately 10% and 7% of total inventories at December 31, 2004 and 2003, respectively.

      We establish reserves for excess or obsolete inventory based on experience.

Property, Plant and Equipment

      Our business is capital-intensive and has required, and will continue to require, significant investments in property, plant and equipment. At June 30, 2005, December 31, 2004 and December 31, 2003, the carrying value of our property, plant and equipment was $6,737 million, $7,136 million, and $7,050 million, respectively. The average of the estimated useful lives of our refineries and petrochemical plants is 20 years. Depreciation for property, plant and equipment is recorded on the straight-line method.

      We estimate the useful lives of our property, plant and equipment based on our historical experience, engineering estimates and industry information. Such lives are reviewed when economic events indicate that we may not be able to recover the carrying value of the assets. Management’s estimates of our assets’ useful lives assume periodic maintenance and an appropriate level of annual capital expenditures. Without ongoing capital improvements and maintenance, the productivity and cost efficiency of our machinery and equipment would decline and the useful lives of our assets would be shorter.

      If the useful life of our property, plant and equipment as of June 30, 2005 were to have been estimated to be one year longer or shorter, our depreciation charge for the six months ended June 30, 2005 would have been $18 million less or $20 million greater, respectively.

Accounting for Business Combinations

      We allocate the purchase price paid for assets acquired and liabilities assumed based on their relative fair value at the date of acquisition pursuant to SFAS No. 141, “Business Combinations.” In estimating the fair value of tangible and intangible assets acquired and liabilities assumed, we consider information obtained during the underlying due diligence process and utilize various valuation methods and measures, including market prices, where available, appraisals, comparisons to transactions for similar assets and liabilities and the net present value of estimated future cash flows.

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Recoverability of Long-Lived Assets

      We review the carrying value of our long-lived assets, including property, plant and equipment and definite-lived intangible assets whenever events or changes in circumstances indicate that the carrying value of the assets may not be fully recoverable. An impairment loss may be recognized when the undiscounted future cash flows expected to result from the use of the asset, including disposition proceeds, are less than the carrying value of the asset. The amount of the impairment loss to be recognized is based on the difference between the estimated fair value and the carrying amounts of the assets. Fair value is generally determined based on a discounted cash flow analysis. In order to determine whether an asset has been impaired, assets are grouped and tested at the bottom of the range of available estimates for identifiable future cash flows.

      The determination of both undiscounted and discounted cash flows requires us to make significant estimates and considers expected future development as of the balance sheet date. Subsequent changes in estimated undiscounted and discounted cash flows arising from changes in anticipated developments could impact the determination of whether an impairment exists, the amount of the impairment charge recorded and whether the effects could materially impact our net income.

Goodwill

      Goodwill represents the excess of the purchase price paid for an asset and related costs over the value assigned to the net tangible and identifiable intangible assets of businesses acquired. At June 30, 2005 and December 31, 2004, we had $258 million and $261 million of goodwill and other intangible assets, respectively. We assess the recoverability of the carrying value of goodwill at least annually or whenever events or changes in circumstances indicate that the carrying value may not be fully recoverable. Recoverability of goodwill is measured at the reporting unit level based on a two-step approach. First, the carrying amount of the reporting unit is compared to its fair value as estimated using a discounted cash flow analysis and terminal value model for expected future cash flows. To the extent that the carrying value of the reporting unit exceeds the fair value of the reporting unit, a second step is performed, whereby the reporting unit’s assets and liabilities are fair valued. The implied fair value of goodwill is calculated as the fair value of the reporting unit in excess of the fair value of all non-goodwill assets and liabilities allocated to the reporting unit. To the extent that the reporting unit’s carrying value of goodwill exceeds its implied fair value, impairment exists and must be recognized. The annual goodwill impairment test requires us to make a number of assumptions and estimates concerning future levels of earnings and cash flow, which are based upon our strategic plans. While we use available information to prepare estimates and to perform the impairment evaluation, actual results could differ significantly resulting in future impairment and losses related to recorded goodwill balances.

Restructuring and Plant Closing Costs

      Restructuring and plant closing costs represent charges related to the closing of plant locations, work force reductions and other cost savings programs. These charges are recorded when management has committed to a plan to implement the relevant measures and incurred a liability related to the plan. Estimates for plant closing costs include write-offs of the carrying value of the relevant plant, any costs incurred for necessary environmental and/or regulatory measures, contract termination costs and demolition costs. Amounts provided for work force reductions and other cost savings programs are based upon estimates of the number of positions to be terminated, termination benefits to be paid and other relevant information. While management evaluates the relevant estimates as of the end of each reporting period and adjusts the reserve when information indicates that the estimate is above or below the initial estimate, management’s estimates on a project-by-project basis historically have not varied to a material degree. See note 15 to our combined financial statements for a further discussion of our restructuring activities in the three years ended December 31, 2004.

Environmental Liabilities and Expenditures

      Because we refine oil products and manufacture and sell a range of petrochemical products, our operations are subject to various hazards incidental to the refining of oil and the production of industrial chemicals, including the use, handling, processing, storage and transportation of hazardous materials. Environmental

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restoration and remediation costs are recorded as liabilities and expensed when site restoration and environmental remediation and cleanup obligations are either known or considered probable and the amount can be reasonably estimated. Environmental accruals are measured based on an evaluation of currently available information with respect to each site, considering factors such as existing technology, currently applicable laws and regulations and our prior experience in the remediation of contaminated sites. The measurement of environmental liabilities is based on a range of estimates of costs required to carry out the remediation efforts. We use our best estimate within this range to establish our environmental accruals. For environmental accruals, actual costs can differ from estimates because of changes in laws and regulations, public expectations, discovery and analysis of site conditions and changes in clean-up technology.

Income Taxes

      We recognize deferred tax assets and liabilities based on the differences between the financial statement carrying amounts and the tax bases and operating losses of our assets and liabilities. We regularly review our deferred tax assets for recoverability and establish a valuation allowance based on historical taxable income, projected future taxable income, the expected timing of the reversals of existing temporary differences and the implementation of tax-planning strategies when we determine that it is more likely than not that we will not be able to realize all or a portion of a deferred tax asset. If we continue to operate at a loss or are unable to generate sufficient future taxable income in the relevant tax jurisdictions or if there is a material change in the applicable effective tax rates or time period within which the underlying temporary differences become taxable or deductible, we could be required to increase our valuation allowance against our deferred tax assets, resulting in an increase in our effective tax rate and a reduction of our net income. We have implemented a centralized procurement and sales organization within Europe along with dedicated manufacturing companies. During periods of low margins, our tax rate will likely increase as our manufacturing companies may earn a profit for their manufacturing services while our central procurement and sales organization may incur losses which will not immediately reduce income taxes.

      Our operating results have been included as a part of BP’s consolidated group for tax purposes. Our provisions for income taxes have been determined on a separate return basis. Pursuant to SFAS No. 109, “Accounting for Income Taxes”, we are required to assess our deferred tax assets and the need for a valuation allowance on a separate return basis and exclude from that assessment the utilization of all or a portion of those losses incurred by BP under the separate return method. This assessment requires considerable judgment on the part of management with respect to benefits that could be realized from future taxable income as well as other positive and negative factors. Because we were unable to accurately determine the amount of pre-2000 deferred tax assets in respect of operating loss carry-forwards and tax credits, we have only recognized current tax benefits in the periods presented equal to, but not exceeding, any deferred tax expense with any excess amounts evaluated. Evaluation allowances were provided for any deferred tax assets to the extent it was not likely that these tax assets would be realized in the future.

Employee Benefit Programs

      We sponsor pension and other post-retirement benefit plans for some of our employees in France and Germany. These plans cover most of our employees in these countries and provide for pension payments to eligible employees upon retirement. Pension benefits for employees generally are based on years of service. Some of our pension plans are unfunded while others are partially funded, consistent with local practice in the relevant jurisdictions.

      The amounts shown in our combined financial statements as net periodic pension costs are determined on an actuarial basis. We use various assumptions in calculating the actuarial valuation of pensions, including weighted average discount rates, rates of increases in compensation levels, and plan withdrawal, turnover and mortality rates. Our net periodic pension costs for all pension plans sponsored by us were $24 million and $24 million for the six months ended June 30, 2005 and 2004, respectively, and $51 million, $71 million and $19 million for the years ended December 31, 2004, 2003 and 2002, respectively.

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      The discount rate we have selected for our pension plans represents our best estimate of the interest rate that should be used to determine the present value of future cash flows currently expected to be required to settle our future pension obligations. Historically, we have determined the discount rate based upon current market indicators, primarily the yield on high-quality corporate fixed-income securities. At December 31, 2004, 2003 and 2002, the weighted-average annual discount rate of our sponsored plans was 5%, 6% and 6%, respectively.

      The rate of compensation increase we have selected represents our best estimate of the annual rate at which the average compensation for our employees included in the plan will increase. Historically, we have determined the rate of compensation increase based on an analysis of historical and projected compensation trends within our industry and specific regions for employees covered by our plans. For the years ended December 31, 2004, 2003 and 2002, the annual rate of compensation increase for our sponsored plans was 4%.

      A change in the two key assumptions of discount rate and rate of compensation increase of 100 basis points would have the following effects on our net periodic pension cost for the year ended December 31, 2004:

	100 basis point
Assumption	Increase			Decrease
	($ in millions)
Discount rate		(6	)		7
Rate of compensation increase		7			(6	)

      Additionally, we have other post-retirement benefit plans that provide for lump sum benefits depending on an employee’s length of service and earnings at, or near, retirement, and post-retirement healthcare benefits in the form of healthcare cost reimbursements for retirees and dependents. These post-retirement benefit plans are also unfunded, in line with local practice in the relevant jurisdictions.

      The amounts recognized in our combined financial statements as other post-retirement benefit costs are determined on an actuarial basis. We use various assumptions in calculating the actuarial valuation of other post-retirement benefit costs, including the weighted average discount rate, health care cost trend rates, and plan withdrawal, turnover and mortality rates. Our other post-retirement benefit cost for all sponsored plans were less than $1 million in each of the six month periods ended June 30, 2005 and 2004, respectively, and $2 million for each of the years ended December 31, 2004, 2003 and 2002.

      The other post-retirement benefit costs described in the paragraph above are calculated using the same discount rate selected for the pension plans.

      A change in the two key assumptions of discount rate and assumed health care cost trend of 100 basis points would have the following effects on our other post-retirement benefit cost for the year ended December 31, 2004:

	100 basis point
Assumption	Increase			Decrease
	($ in millions)
Discount rate		(1	)		1
Assumed health care cost trend		1			(1	)

      In addition, we incur costs related to pension plans and other post-retirement benefit plans sponsored by the BP group that also cover certain of our employees. These costs are generally allocated to us based on BP’s calculation of net periodic pension cost and an assessment of our share of such costs given our employee and retiree base. Aggregate allocated costs for BP-sponsored pension and post-retirement benefit plans incurred by us were $29 million and $26 million for the six months ended June 30, 2005 and 2004, respectively, and $55 million, $(1) million, and $(8) million for the years ended December 31, 2004, 2003, and 2002, respectively.

Recent Accounting Pronouncements

      For information on recent accounting pronouncements, please see “Notes to Combined Financial Statements — Adoption of New Accounting Standards” and “Notes to Combined Financial Statements — Recently Issued Accounting Standards.”

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INDUSTRY OVERVIEW

Petrochemicals

Market Environment

      The petrochemical industry produces olefins and polymers and manufactures various petrochemical products directly or indirectly derived from olefins. The olefins industry is primarily regional, with market dynamics and prices varying between regions, while the polymers and derivatives industries and the plastics, rubbers and fibers industries served by them are becoming increasingly global. The petrochemical industry is highly commoditized. Some petrochemical products, mainly polymers and derivatives, have characteristics which permit petrochemical companies to engage in price differentiation, but these products account for a small portion of the overall market and most of them may become commodities at some point in their lifecycle.

Cyclicality and Volatility

      The relationship between supply and demand in the petrochemical industry historically has been highly cyclical, with margins typically increasing when demand approaches or exceeds available supply. This is primarily because product supply is driven by periods of substantial capacity additions and followed by periods in which no or limited capacity is added. In addition, product demand fluctuates with overall economic conditions.

      As a general matter, companies are more likely to add capacity in periods when current or expected future demand is strong and margins are, or are expected to be, high. Investments in new capacity can result, and in the past frequently have resulted, in overcapacity, which typically leads to a reduction of margins. In response, companies typically reduce capacity or limit further capacity additions, eventually causing the market to be relatively undersupplied. The alternation between periods of substantial capacity addition and periods of limited capacity addition, or even capacity reduction, produces recognizable swings in petrochemical capacity utilization, which typically result in swings in industry margins. This long-term pattern is often referred to as the petrochemical cycle.

      Margins are also susceptible to potentially significant swings in the short term. This volatility, which may be global or isolated in individual regions, can be caused by a number of factors, including fluctuations in utilization rates due to planned or unplanned plant outages, political and economic conditions driving rapid changes in prices for key feedstocks, exchange rate fluctuations and changes in inventory management policies by customers of the petrochemical industry.

      Because the petrochemical industry’s profitability historically has been highly correlated with swings in utilization of the industry’s ethylene capacity, the petrochemical cycle is often described by reference to the ethylene cycle. The bottom of the last cycle was reached in 2001 and continued through 2003 due to weak demand and substantial capacity additions.

      Since 2004, stronger demand and limited capacity additions have led to improved utilization rates and rising profit margins. While a number of industry observers, including CMAI, a chemicals consulting company, have forecast that the current recovery of the ethylene cycle may last longer than previous upturns, the duration of the present upturn is difficult to predict and depends on a number of factors, including the extent of the global economic expansion and the amount of capacity that will be built over the coming years. Those observers who predict an extended upturn believe that, among other things, the prevailing high level of energy prices and low growth in the consumption of petrochemical products in North America and Europe may cause petrochemical companies to focus their investments in these regions on de-bottlenecking existing facilities, rather than adding new capacity. Given that there are several recently completed world-scale petrochemical complexes which will be able to meet growth requirements over the coming years and the absence of recent announcements of large-scale construction projects, CMAI forecasts that there will likely not be a substantial increase in industry capacity in these two regions before 2010. However, CMAI expects that the majority of new ethylene capacity will be built in the Middle East to take advantage of the low-cost gas feedstock available in this region. Although some of this new capacity could be used to supply product to Europe, the majority of production is expected to be exported to Asia. According to CMAI, the demand growth projected for China should absorb a significant proportion of the

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capacity expected to be added in the Middle East over the next several years. However, if demand in China fails to reach current projections, a greater proportion of the product manufactured in the Middle East would likely be delivered to Europe, potentially resulting in an oversupply of the European market.

Petrochemical Feedstock

      The principal feedstocks of our petrochemical business are naphtha and gas. Naphtha is mainly obtained in the process of refining crude oil. Gas is recovered either from oil in the form of associated gas obtained together with oil and natural gas liquids (NGL), or directly from gas fields. Gas includes ethane, butane and propane. Butane and propane are transported and stored as liquids, referred to as liquified petroleum gas (LPG).

      For most petrochemical processes, feedstock costs are the most significant cost item. The costs of the feedstocks we require to make our petrochemical products (naphtha, ethane, butane and propane) are principally driven by the price of oil and natural gas. Oil and gas prices are influenced by numerous factors, including the balance between supply and demand and geopolitical factors, making accurate price forecasts virtually impossible. Because gas is not as readily transportable between regions as oil and the amount of interregional trade in gas is thus limited, gas prices tend to vary by geographic region. In the current environment of high oil prices, petrochemical facilities located in the Middle East enjoy the advantage of direct access to gas feedstocks which are priced at a significant advantage to naphtha. To the extent petrochemical companies are integrated with their feedstock sources, are geographically diversified or have the ability to change their feedstock mix quickly and easily, they are better able to manage the volatility in oil and gas prices than other petrochemical manufacturers. Also, petrochemical producers with a more diversified product portfolio are less exposed to price movements in any single product category.

Petrochemical Products

      According to CMAI, worldwide demand for petrochemical products has grown steadily over the past 15 years at a greater rate than the growth rate of gross domestic product (GDP), reflecting the ongoing substitution of thermoplastics for other industrial materials, including glass, metal, wood and paper. CMAI projects demand growth for petrochemical products to moderate slightly from historical levels but still to grow slightly faster than GDP, despite petrochemical growth rates below GDP growth rates in North America and western Europe. For 2006, CMAI projects GDP to grow at an annual rate of 3.6% in North America, 2.3% in western Europe and 5.1% in north east Asia, excluding Japan. Within north east Asia, China is expected to experience the strongest growth, with a projected growth of 8.0% for 2006.

      GDP and demand growth rates vary not only by region but also among different types of petrochemical products, as detailed in the table below:

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Average annual GDP and demand growth rates⁽¹⁾⁽²⁾

		1999-2004								2004-2009
		North		Western		North				North		Western		North
		America		Europe		east Asia		Global		America		Europe		east Asia		Global
		(%)
GDP			2.7		1.9		3.3		2.8		3.6		2.3		3.5		3.4
Ethylene			0.6		2.2		4.3		3.4		0.7		1.2		4.0		4.6
Propylene			2.8		2.7		5.9		5.2		2.7		0.6		4.8		4.9
Butadiene			0.3		3.9		4.7		3.0		0.8		1.4		4.2		2.9
Polyethylene			1.6		2.5		6.1		4.0		3.5		2.7		6.5		4.8
	HDPE		1.9		3.5		7.0		4.5		4.1		4.1		6.5		5.5
	LDPE		(0.3)		(0.7)		3.6		1.4		1.2		0.1		5.3		2.5
	LLDPE		2.6		6.3		7.4		6.1		4.2		3.7		7.4		5.8
Polypropylene			3.2		3.6		8.1		6.1		4.1		3.1		5.6		5.4
Styrene			(0.4)		1.1		6.9		3.6		2.1		1.4		5.1		3.7
Polystyrene			(1.4)		(0.5)		2.2		1.1		1.6		1.5		3.7		3.1
Acrylonitrile			0		(1.2)		5.5		2.7		(0.3)		0		4.3		2.7
Alpha olefins			4.7		4.1		4.9		6.0		(1.3)		4.3		0.5		2.7
Ethylene oxide			2.0		3.3		6.6		4.7		(4.0)		(1.3)		4.2		5.3
Propylene oxide			3.8		6.6		10.1		6.0		3.0		0.9		4.8		2.7

(1)	Source: CMAI, July 2005.
(2)	The growth rates shown for each region reflect the growth of domestic demand in that region.

     Set forth below is an overview of the principal petrochemical products and their applications.

•  Ethylene. Ethylene is a flammable gas obtained in a process called cracking, in which hydrocarbons are briefly heated to 750-950 °C, causing chemical reactions that split the carbon-hydrogen or carbon-carbon bonds of the feedstock. The chemical mixture resulting from cracking contains ethylene, propylene, butadiene and other compounds in varying amounts depending on the feedstock. The majority of this mixture is in the form of ethylene. Because ethylene is a gas, it must be transported either by pipeline or in the form of highly pressurized or refrigerated liquids, which is expensive. While ethylene itself has no consumer applications, it is a key building block for polyethylene, polystyrene, EO and other derivatives.

        According to CMAI, ethylene is the most widely consumed petrochemical product in the world. Global ethylene demand is primarily driven by the use of ethylene as a feedstock for the production of polyethylene. Other important demand drivers include the use of ethylene in the manufacture of EO, ethylene dichloride and ethylbenzene.

•  Propylene. Propylene is a flammable gas which is derived either as a co-product of the refinery FCC process used to make gasoline or as a co-product of the steam cracking process used to make ethylene. While propylene has virtually no independent end use, it is an important input for a significant number of industrial products and the main feedstock for polypropylene and acrylonitrile. Propylene is marginally easier to transport than ethylene and may be shipped by pipeline, road, rail or ship.

        Global propylene demand is primarily driven by the use of propylene as a feedstock for the production of polypropylene. Other important demand drivers include the use of propylene in the manufacture of acrylonitrile, propylene oxide (PO), oxo-alcohols, cumene and acrylic acid.

•  Styrene. Styrene, a hydrocarbon which under normal conditions is a flammable liquid, is derived from ethylene and benzene, which are brought together in a reaction with a catalyst to form ethylbenzene. Virtually all worldwide ethylbenzene production is consumed in the manufacture of styrene. The largest use of styrene is in the production of polystyrene. It is also used, in combination with acrylonitrile, in the manufacture of styrene-acrylonitrile (SAN). SAN has a variety of applications, including housewares and appliances. In combination with butadiene, styrene is also used in the manufacture of styrene-butadiene rubber (SBR) and styrene-butadiene latex (SBL), two common types of synthetic rubbers, and to make

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acrylonitrile-butadiene styrene (ABS), a plastic with a high degree of tensile strength and a variety of end uses.

        Styrene demand is mainly driven by various types of polystyrene, with general purpose polystyrene and EPS accounting for approximately two thirds of global demand. According to CMAI, China will be the principal driver of demand growth for styrene in the future as industrial users of polystyrene, EPS and ABS are moving their operations to this region.

•  Butadiene. Butadiene is a gas which condenses to a liquid at minus 4.5°C. It is one of the co-products of the steam cracking process used to manufacture ethylene and propylene, and can also be made from NGL through chemical transformations or the separation of natural components. Butadiene is used primarily in the production of polymers, principally synthetic rubbers such as SBR, which is used to make tires and other rubber products. Other polymers made from butadiene include ABS and SBL.

        Butadiene demand is driven primarily by growth in consumption of synthetic rubber.

•  Polyethylene. Polyethylene is the world’s most widely used thermoplastic. A thermoplastic is a plastic which softens when heated and hardens again when cooled. Polyethylene is made by aggregating many ethylene molecules in a process called polymerization. Polyethylene has a wide variety of applications, including soft plastics, such as those used in plastic films, hard plastics such as those used in plastic bottles and extremely hard plastics found, for example, in bulletproof vests.

        Polyethylene is often classified by its density, because the denser the polyethylene used in a material, the greater the material’s rigidity. The world’s largest volume polyethylene is HDPE, which has a relatively high degree of tensile strength. Its most common household use is plastic containers. At the opposite end of the spectrum is LDPE, which was the first type of polyethylene to be developed. Its most common household use is plastic bags. Both HDPE and LDPE are also commonly used for molding applications. LLDPE, which was developed in the 1970s and can usually be manufactured at a lower cost than LDPE, has basic properties similar to LDPE. While LDPE and LLDPE are to a certain extent substitutable for each other, for certain applications one of them is usually more suitable than the other.

        Film is the largest use of global polyethylene production and the primary driver of demand, representing approximately one half of worldwide polyethylene consumption. Film includes a myriad of end use applications, from food packaging to trash bags, stretch films and shrink films. Blow-molding and injection-molding are the next largest uses and are also important demand drivers. In the blow-molded category, blow-molded bottles are the single largest end use.

•  Polypropylene. Polypropylene is the world’s second most widely-used thermoplastic after polyethylene. It is a thermoplastic characterized by its rigidity and resistance to high temperatures, chemicals and fatigue. Polypropylene has a heat distortion temperature of 150 to 200 °C, which makes it particularly suitable for “hot-fill” applications, which are manufactured using injection molding production methods. As a result, polypropylene is the most significant material used in molded containers and automotive applications. In addition, polypropylene can be configured to a high degree of purity, making it useful for the semiconductor industry. Polypropylene fibers are also used in fabrics and carpets.

        Polypropylene represents the largest category of thermoplastics, and it is among the fastest growing categories of thermoplastics. The fast growth of polypropylene-based products reflects the superior cost and performance characteristics of this material. As one of the industry’s most versatile and historically least expensive polymers, polypropylene is achieving a portion of its growth by displacing other polymers, such as polyethylene and polystyrene. The largest end use segment of the polypropylene industry is injection-molding, followed by film and sheet. Injection-molded polypropylene includes a wide variety of end uses, such as packaging, automotive and appliances. End use segments for film and sheet include food bags, tape and wrappings for consumer goods. According to CMAI, North America, western Europe and north-east Asia will account for approximately 75% of global demand in 2005. CMAI expects that Asia will continue to grow at higher rates than North America and Europe, primarily as a result of growth in the Chinese market.

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•  Polystyrene. General purpose, or “crystal,” polystyrene and high impact polystyrene are hard and brittle materials which are used for packaging, appliance and electrical housings and insulation. Both forms are also used for plastic molding applications. Styrene is the main feedstock used to make polystyrene. EPS is used to manufacture lightweight foam for packaging and insulation purposes.

        The largest demand driver for polystyrene is rigid durable products, such as television and computer cabinets.

•  Solvents and industrial chemicals. Solvents are used to dissolve solids and keep them in liquid form. They serve a variety of industrial and consumer markets, including in the pharmaceuticals, cosmetics, inks, adhesives, detergents and coatings industries. One important solvent is ethanol. Important industrial chemicals include EO, ethylene glycols (EG), PO and propylene glycols (PG). EO is used mainly to make EG and industrial detergents, and EG is, in turn, primarily used in the manufacture of polyesters and antifreeze/coolants. PO is used to make PG, which, in turn, is primarily used to produce polyester, paints and coatings, airplane de-icers, antifreeze and industrial coolants.

        EO demand is driven by demand for EO derivatives, principally EG. In recent years, EG has become the most important derivative of EO. As a result of increased consumption of polyester, EG has become the second largest application of ethylene after polyethylene. The lack of sufficient supplies of EG to satisfy demand for polyester has recently fueled a strong market environment. Similarly, PO demand is driven by demand for PO derivatives, principally PG.

•  Acrylonitrile. Acrylonitrile is a well-established commodity that has been in commercial use for more than 70 years. It is used in the production of acrylic fiber, ABS and SAN. Acrylic fiber is used in a wide variety of consumer products, including clothing and carpets. Acrylonitrile is manufactured from propylene, ammonia and air with the use of a special catalyst. Acrylonitrile is toxic and flammable and, unless chemical stabilizers are added for storage and shipment, can undergo an explosive chemical reaction.

        Historically, acrylonitrile demand has been driven by acrylic fiber. More recently, ABS and SAN polymers have taken over as the main drivers of demand for acrylonitrile, with annual growth rates of approximately 4% over the past four years. As with other petrochemicals, the growth in demand for ABS and SAN polymers has been fueled by Asia while demand in North America and Europe has declined. Currently, Asia is a net importer of acrylonitrile. Much of the Asian imports come from North America.

•  Alpha olefins. Alpha olefins include LAOs and PAOs. LAOs are hydrocarbons in a chain formation with physical characteristics and commercial uses that vary according to the length of the hydrocarbon chain. Ethylene is the primary feedstock for the production of LAOs, and LAOs, in turn, are important feedstocks for the manufacture of certain types of polyethylene. In addition, they have many applications in the petrochemical industry, including as surfactant intermediates, base oil for synthetic lubricants and drilling fluids. Demand for LAOs has increased substantially since they first became commercially available. PAOs, which are made by merging several LAOs together, are primarily used as synthetic lubricants. PAOs are value-added products compared with LAOs, and, accordingly, command higher margins. However, PAOs account for only approximately 10% of the overall market for alpha olefins.

        Producers of LAOs may be divided into two groups: “full-range” producers, which manufacture a whole range of LAOs and “on purpose” or “single product” producers, which specialize in those LAOs which historically have experienced the fastest growth. Demand for LAOs has experienced an increasing divergence between demand for LAOs with shorter carbon chains, which have grown more quickly, and demand for LAOs with higher carbon numbers, which on average have experienced slower growth. As a result, the industry has focused on developing single product technologies to target the fastest growing LAOs. Demand for PAOs is driven by the European automotive industry and lubricant substitutes. Following a period of flat demand for PAOs in North America, North American PAO demand has recently shown signs of improvement.

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•  PIB. PIB is a synthetic hydrocarbon polymer available in a wide variety of viscosities for use in a broad range of industrial applications, such as lubricants and fuel additives, and consumer applications, such as adhesives and sealants.

Consolidation

      Several of the major oil companies have recently restructured their petrochemical businesses. At the same time, there has been a trend in the North American and European petrochemical industry since the early 1980s towards consolidation, a development which has gained pace during the 1990s. At the global level, the industry is still relatively fragmented due to the continuous emergence of new manufacturers, primarily in the Middle East but also in Asia. The world’s top ten ethylene and propylene producers, for example, account for less than 50% of global capacity for the relevant products.

Regional Outlook

      It is expected that few new olefins crackers will be built in North America and Europe, with the exception of Russia, which, although not currently a focus of foreign investment, potentially has low-cost gas feedstock reserves and thus may attract new projects in the future. Instead, petrochemical companies operating in North America and Europe are expected to focus on upgrading and expanding existing facilities. Slower demand growth in these regions relative to China and the rest of Asia and fewer sources of low-cost feedstocks compared with the Middle East are the primary drivers behind this outlook. Another contributing factor is the fact that the North American and European petrochemical industries are becoming subject to ever more stringent environmental laws and regulations. Although significant merger and acquisition activity in Europe in recent years has led to consolidation, much of the infrastructure is still local. Several projects to address this problem are underway, including connecting the principal ethylene pipeline networks in Europe and building a European propylene pipeline.

      While only very few facilities are thus expected to be built in North America and Europe, significant projects are underway in Asia and the Middle East. Petrochemical investments in Asia are primarily targeted at China and surrounding countries to take advantage of the strong growth of the Chinese manufacturing industry. The growth in Chinese exports, along with increased local demand as China grows, are driving demand growth for petrochemical products, much of which is met through imports. While new capacity is expected to come on-stream in China over the next several years, it is expected that, for the foreseeable future, China’s strong demand growth will exceed supply growth and China will remain a major importing country of petrochemical products.

      The Middle East is attracting investment in petrochemical capacity because of its significant reserves of low-cost gas feedstock obtained as a co-product of the oil production process. There is political support in many Middle Eastern countries for building an export-oriented industry around these gas reserves, and joint ventures with foreign companies providing technology expertise and market access are supported as a means of exploiting these reserves. As discussed above, much of the capacity in the Middle East is being built for export to China. However, as the capacity buildup continues, some product may be exported to Europe and the Americas. Furthermore, if China fails to grow as expected, substantially greater volumes may be directed from the Middle East to North America and Europe.

Refining in Europe

      The refining industry in Europe historically has been characterized by steady growth in demand for refinery products, cyclical margins due to periodic overcapacity and supply shortages in various regional markets, and seasonal fluctuations in the consumption of particular types of refinery products, such as gasoline and diesel during the summer driving season in the northern hemisphere and home heating oil during the winter months.

      In aggregate, refining industry margins have experienced a sharp upturn since 2002 to reach record levels in late 2004. With growth in product demand exceeding capacity additions, and crude oil supply shifting towards heavier and higher sulfur crudes, refineries with more sophisticated technical configurations have been able to capture greater margins. According to PGI, the average cash margin for a hydrocracking refinery in north west

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Europe was $6.04 per barrel in 2004 and $6.15 in the six months ended June 30, 2005, compared with $2.73 per barrel in 2003.

      The current supply and demand fundamentals should continue to underpin refining cash margins in the immediate future, and therefore margins are expected to stay above the European historical average during the period from 1992 to 2002 of approximately $1.50 per barrel. Furthermore, with global inventories remaining relatively low, and tightening product specifications limiting the flexibility of the global supply system, the risk of supply disruptions remains high, with associated volatility in product prices and cash margins.

      Crude oil distillation capacity in Europe has declined slightly over the past five years, from 15.3 million barrels per day in 1999 to 15.2 million barrels per day in 2004. The industry still has some spare capacity left but the amount of this extra capacity is declining. According to PGI, industry utilization rates in Europe have increased since 2002 and averaged 91.6% in the six months ended June 30, 2005. No new crude oil distillation capacity is expected to be built in the foreseeable future, due principally to the high cost of entry into the European refining markets and the capital to comply with increasingly stricter environmental standards. Furthermore, the process of planning, obtaining permission to build and constructing a new refinery typically takes between three and four years, and therefore capacity forecasts may be made with a high degree of certainty for up to three years. Instead of building new refining capacity, refinery operators are expected to focus their investments on de-bottlenecking and upgrading existing production facilities to enable them to process higher volumes of crude oil and to manufacture higher volumes of more valuable products. These investments are expected to be driven by changes in consumption patterns and the introduction of stricter environmental laws and regulations, such as clean fuels legislation.

      The quality of crude oil dictates the level of processing and conversion necessary to achieve the optimal mix of finished refinery products. For these purposes, crude oil may be classified by its density (ranging from light to heavy) and sulfur content (ranging from sweet to sour). Light, sweet crude oils are more expensive than heavy, sour crude oils because they require less treatment and produce a slate of products with a greater percentage of high-value refinery products, such as gasoline, naphtha and kerosene. The heavy, sour crude oils typically sell at a discount to the lighter, sweet crude oils because they produce a greater percentage of lower-value products with simple distillation and require additional processing to produce the higher-value light products. We believe that increasing worldwide supplies of heavy, sour crude oil will result in continuing cost advantages for refineries with complex configurations which are able to process these crude oils. The upgrading capability, or complexity, of a refinery is a measure of its ability to process less expensive feedstock, such as heavier and higher-sulfur content crude oils, into lighter value-added products, such as gasoline, diesel and jet fuel. The greater a refinery’s complexity and the more flexible its feedstock slate, the better positioned it is to take advantage of the more cost-effective crude oils, resulting in incremental cash margins. From 2002 to 2004, the price differential between light, sweet crude oil and heavy, sour crude oil widened substantially. According to PGI, this price differential (as measured by the Urals/ Brent differential) averaged $4.14 per barrel in 2004 and $4.33 per barrel in the six months ended June 30, 2005, compared with $1.76 per barrel in 2003. In Europe, the average crude oil quality is expected to decline, as significant volumes of sour crude oils are expected to be imported from the countries of the former Soviet Union.

      The main refinery products, apart from naphtha, which is used as a petrochemical feedstock, are gasoline, middle distillates, jet fuel and kerosene, and fuel oil. Middle distillates, or gas oils, include road diesel, light gas oils, which are used as industrial and commercial fuels, and heavy gas oils, which are used as refinery feedstock. Fuel oil is used by marine vessels, power plants, commercial buildings and industrial facilities for heating and processing.

      The most important transport fuels are gasoline and diesel. Refineries blend together various gasoline components to achieve specifications for regular and premium grades in both summer and winter formulations. Additives are often used to enhance the performance of gasoline and provide protection against oxidation and rust formation. According to PGI, in European countries that are members of the Organization for Economic Cooperation and Development (OECD Europe) there is an overall net gasoline surplus of approximately 210 million barrels per year. Most of this surplus is exported to the United States but tight quality specifications

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make it difficult for some refineries to comply with U.S. requirements. Other gasoline destinations are eastern Europe, the countries of the former Soviet Union and Africa.

      Specifications for fuel products are becoming more and more stringent. By 2009, transport fuels such as gasoline and diesel are expected to have to comply with a 10 parts per million (ppm) maximum sulfur specification in the European Union. This constitutes a significant reduction from the 50 ppm of sulfur currently permitted by European Union diesel and gasoline specifications, as well as the 500 ppm of sulfur (which will be reduced to 15 ppm beginning June 1, 2006) and the 30 ppm of sulfur currently permitted by the more restrictive specifications for diesel and gasoline, respectively, in the United States. To comply with these stringent specifications, refineries must make expensive technology upgrades.

      With respect to middle distillates, western Europe has a net deficit of approximately 148 million barrels per year. Most of this shortfall is imported from the countries of the former Soviet Union. These imports typically require further processing to reduce the oil’s sulfur content before they can be marketed.

      Fuel oil is balanced in northern Europe, with a small excess in high sulfur grades. Southern Europe has a deficit of fuel oil resulting in net imports of approximately 33 million barrels per year, which come predominantly from northern Europe and Africa. However, imports have significantly declined over the last ten years in line with declines in consumption.

      Further details on the growth outlook for each major type of refinery product are provided below:

•  Naphtha. According to PGI, demand for naphtha increased by 0.8% in 2004 in OECD Europe. Naphtha demand is primarily driven by the petrochemical industry. North west Europe has a growing deficit position in naphtha, which is met by imports from the Middle East and the Mediterranean.

•  Gasoline. Although gasoline demand is seasonal and peaks during the summer months, the long-term trend is clearly toward a sustained decline, reflecting the continued replacement of gasoline-powered vehicles with vehicles powered by diesel and benefiting from greater engine efficiency. PGI reports a decline of 1.7% in gasoline demand in OECD Europe for 2004 and forecasts further declines of 2.5% and 2.0% for 2005 and 2006, respectively. The excess supply in Europe is expected to increase steadily as demand continues to decrease, while production remains broadly flat. By contrast, in North America, demand for gasoline is expected to continue to increase at faster rates than the increase in North American supply, which in turn should enable European manufacturers to export their surplus to North America.

•  Diesel and heating gas oil. According to PGI, in 2004, road diesel demand in Europe continued to grow strongly at 4.6%, led by the United Kingdom, which experienced growth at a rate of 7.9%. Road diesel is expected to show a consistent and significant uptrend for the foreseeable future. PGI forecasts gas oil/diesel growth rates of 1.8% and 1.6% for 2005 and 2006, respectively. In contrast to road diesel, which has its seasonal peak in the summer and is set for positive growth, demand for heating gas oil peaks in the winter and is expected to continue to decline. The diesel and heating gas oil shortfall in Europe is covered by imports from the countries of the former Soviet Union.

•  Jet fuel and kerosene. According to PGI, demand for jet fuel and kerosene in OECD Europe grew by 4.4% in 2004. Going forward, jet fuel demand in Europe is expected to grow faster than any other transportation fuel, driven by increasing air traffic. According to PGI, kerosene consumption in OECD Europe will grow at a rate of 2.9% for each of 2005 and 2006. Given north west Europe’s deficit position and flat capacity, this region is expected to increasingly rely on imports from the Middle East and the Mediterranean.

•  Fuel oil. According to PGI, demand in OECD Europe for fuel oil, both high sulfur and low sulfur, declined by 0.9% in 2004. Fuel oil demand is expected to continue to decline as a result of emissions restrictions, including sulfurous and nitrous emissions, and a continuing shift to natural gas as a source of fuel. PGI forecasts a further decline of 2% for each of 2005 and 2006 in OECD Europe. However, the marine bunker fuel market is expected to remain strong, particularly in the Mediterranean markets.

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BUSINESS

Introduction

      We are among the world’s largest petrochemical companies with revenues of $17.9 billion in 2004. We conduct our business through petrochemical manufacturing sites in eight countries, as well as two refineries which are fully integrated with our petrochemical facilities. At June 30, 2005, our total petrochemical production capacity was approximately 40 billion pounds per year and our refineries had a combined crude oil distillation capacity of approximately 400 mbd. Our business is structured around five major sites, which account for approximately 70% of our petrochemical production volumes and approximately 85% of our overall production volumes.

      We have a global reach and leading market positions with respect to our key petrochemical products, which enable us to manage our business on a worldwide basis. We benefit from the cost advantages of operating large-scale petrochemical facilities and the high degree of integration at our major sites. We have an expanding position in the fast-growing Asian markets, which we serve through our operations in North America and Europe. We have an established regional office in Shanghai, China to manage our operations in Asia. Our competitive position in the petrochemical industry is supported by a portfolio of proprietary process technologies. Our two European refineries have the scale, location, product slate, feedstock flexibility and clean fuels capabilities necessary to be competitive in their respective markets and provide an earnings stream that is not driven by the same cyclical patterns as our petrochemical businesses. Our safety performance track record is among the best in the industry.

      Our business comprises certain assets, liabilities and associated infrastructure that were formerly part of BP’s Petrochemicals, Refining and Marketing, and Gas, Power and Renewables segments. We believe our separation from BP has created new opportunities for us. Historically, our business was a small part of a much larger organization and our performance lagged behind that of other companies in the petrochemicals sector. As a separate entity with our own management structure, we will be able to focus on the factors that are critical to the success of our petrochemical and refining businesses and benchmark ourselves directly against the performance of our competitors. Our benchmarking work has identified significant opportunities to improve the performance and optimize the use of our existing assets and to increase our margins. We intend to pursue growth opportunities by investing in new assets and forming joint ventures in regions that have access to low-cost feedstocks.

      In connection with our formation as a separate legal entity, BP has agreed to provide various administrative and operational support services to us. In addition, we have entered into a range of commercial arrangements with BP for the supply of refining and petrochemical feedstocks, the purchase and sale of our refined products, the sharing of common infrastructure and the provision of utilities at various sites which we share with BP. See “Certain Relationships and Related Transactions — Commercial Interface Agreements” for more information on these arrangements.

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      The following chart provides an overview of our two principal businesses, the segments which each business comprises and the products we make in each of these segments:

(1)	Intersegmental sales amounted to $1,909 million for the year ended December 31, 2004.
(2)	For more information on how we calculate adjusted EBITDA, see “Selected Combined Financial Data — Use of Non-GAAP Financial Measures.”

     In our petrochemical business, we make olefins and related products, a broad range of polymers and various other petrochemical products directly or indirectly derived from olefins. The focus of our olefins business is on ethylene and propylene, which are the two largest volume olefins and key building blocks for polymers and derivatives. The olefins we make are primarily used as feedstock for our polymers and derivatives businesses. In addition, we sell olefins to third party customers for a variety of industrial and consumer applications involving plastics, rubber and fiber. In our polymers business, we focus on polyethylene and polypropylene. The largest volume product of our global derivatives business is acrylonitrile. See “— Products” for more information on the markets in which we sell our products. We are among the largest volume manufacturers of olefins and polymers in the world. In addition, we have developed several proprietary process technologies for the production of polymers, including our gas phase polyethylene and polypropylene processes, which we use both internally and license to customers, and our HDPE process, which we use internally. In addition, we have developed the market-leading acrylonitrile manufacturing technology and related catalysts, which are used in more than 90% of acrylonitrile production processes in the world.

      The following table provides an overview of our capacity, global market position and certain regional market positions with respect to our key petrochemical products:

	Full-year
	capacity(1)		Global
	as of June		market		Selected regional
Key products	30, 2005		position(2)		market positions(2)
	(mmlbs)
Ethylene		8,860		#7		#4 in Europe
Polypropylene		5,680		#3		#2 in North America
HDPE		4,780		#3		#2 in Europe
						#4 in North America
Propylene		3,830		#9		#4 in Europe
Acrylonitrile		2,010		#1		#1 in Europe
						#1 in North America
Other		15,200
Total		40,360

(1)	Capacity is defined as nameplate capacity. See “Business — Manufacturing — Overview” for more information on how we calculate capacity.
(2)	According to Chemical Markets Associates, Inc. (CMAI) data as of July 2005.

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      Our petrochemical business has developed significantly over the past five years. We obtained full ownership of our Cologne, Germany, site in 2001 when we acquired Bayer AG’s (Bayer’s) 50% stake in Erdölchemie GmbH, a joint venture between us and Bayer that had been existence since 1957. In 2001, we acquired Solvay’s U.S. and European polypropylene businesses. At the same time, we combined our HDPE businesses to form BP Solvay Polyethylene North America, in which we owned a 49% stake, and BP Solvay Polyethylene Europe, in which we owned a 50% stake. We contributed the HDPE units of our Grangemouth, United Kingdom, and Lavéra, France, sites to these joint ventures. In November 2004, Solvay exercised its put option with respect to these joint ventures. As a result, we obtained full ownership of the HDPE operations at our Grangemouth and Lavéra sites, as well as our Battleground, Texas, Lillo, Belgium, Rosignano, Italy, and Sarralbe, France, sites. In the three years ended December 31, 2004, we started a program of restructuring our polymers and derivatives assets in North America and Europe with a view to rationalizing and modernizing our asset base. In May 2005, we signed an agreement with NOVA to establish a 50/50 joint venture. Under the agreement, we and NOVA will contribute our respective European polystyrene and EPS businesses to the joint venture.

      In our refining business, we operate two large refineries in Grangemouth and Lavéra. Our principal refining products are transport fuels, particularly diesel fuel and gasoline, naphtha, and heating and fuel oils. Our refineries are physically integrated with petrochemical plants located at the same sites. We have recently implemented a single management structure at these sites to further leverage the benefits of integration. The majority of the naphtha output of our refineries is used as inputs by the petrochemical plants located at the relevant sites. We have entered into agreements with BP pursuant to which BP has agreed to buy the balance of our refinery products and to either market these products to its local customers or trade them on the commodity markets on our behalf.

      Both of our refineries have made substantial investments to bring their units into compliance with European Union clean fuels specifications. Clean fuels are low-polluting transport fuels which are capable of replacing ordinary gasoline and diesel, including unleaded, low benzene, low sulfur gasoline and low sulfur diesel. Both refineries are able to produce clean fuels meeting current European Union specifications. Grangemouth is also able to manufacture clean fuels in accordance with the stricter rules currently applicable in certain parts of the United States and the even more stringent specifications that are expected to become applicable in the European Union in 2009. Lavéra is compliant with current European Union specifications, and we are in the process of making further investments in the refinery to achieve compliance with the expected 2009 European Union specifications by the end of 2007.

      Following reliability issues at several of our key petrochemical and refinery facilities, including Chocolate Bayou, Texas, Grangemouth and Lavéra in 2000 and 2001, we made substantial investments. We believe that these programs have resulted in better reliability and expect to achieve further improvements in the future.

      We have approximately 8,000 employees.

Competitive Strengths

      Our key competitive strengths are the following:

•  Global Reach and Leading Market positions. We are among the world’s largest petrochemical companies with 24 manufacturing sites in eight countries in North America and Europe and a total petrochemical production capacity of approximately 40 billion pounds per year. From these sites, we serve approximately 2,700 customers who are located in the principal industrial regions of the world and use our products across a broad range of end-use applications, which we believe has allowed us to achieve and hold leading market positions with respect to each of our key products. According to CMAI, as measured by expected average annual capacity for 2005, we are among the top three companies globally for each of HDPE, polypropylene and acrylonitrile. We believe that our access to the world’s principal markets and our leading positions with respect to key products enable us to identify and capture demand opportunities in all major market centers.

•  Vertically Integrated, Large Scale Producer. We have five large-scale sites, accounting for approximately 85% of our total production volumes. All of these large-scale sites are integrated with major

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	crackers and polymers and derivatives units, giving us the ability to capture margins across the value chain. Two of them are also integrated with onsite refineries, which differentiates us from many of our competitors. In addition, we own and operate several large global derivatives sites, including the largest acrylonitrile site in the world. We believe the scale and integration of our key sites enable us to realize economies of scale, improve energy management and minimize logistics costs. In addition, this gives us flexibility to adjust our product slate to capture greater value, which is particularly important in volatile markets. We believe that the scale of our global operations provides benefits by reducing our selling, administrative, and research and development costs on a per unit basis.
•	Strong Refining Platform. We own and operate two refineries focused on serving their respective markets with the product slate, feedstock flexibility and clean fuels capabilities necessary to be competitive. Each of our Grangemouth and Lavéra refineries has a crude oil distillation capacity exceeding 200 mbd, which is larger than the average refinery size of each of our top five European refining competitors. Each of our refineries is equipped with an HC and an FCC, which provides them with significant flexibility in processing heavy, sour crude oils into light, sweet middle distillates. The product slates of our refineries are geared to their respective markets, with Lavéra focusing on middle distillates and Grangemouth focusing on gasoline and gasoline blending components. Both refineries are able to produce clean fuels meeting current European requirements. Furthermore, Grangemouth already complies with the more stringent standards for clean fuels expected to become applicable in 2009, and we expect to achieve the same capability in Lavéra by the end of 2007.
•	Extensive Portfolio of Leading Proprietary Technologies. Our technologies are positioned around our key products, including our gas phase polyethylene, gas phase polypropylene, slurry HDPE and acrylonitrile technologies. We believe that our technologies are recognized as being among the lowest-cost in the petrochemical industry. As a result of their low cost, our technologies are widely used in the industry. For example, according to Nexant, Inc. (Nexant), our acrylonitrile technology is used in more than 90% of the world’s acrylonitrile production, while our gas phase polyethylene technology is used in 15% of worldwide LLDPE/ HDPE capacity. The successful recent completion of a large petrochemical complex in Shanghai, China, which is operated by Shanghai SECCO Petrochemical Company Limited (SECCO) and which was designed and constructed by our and BP’s employees in collaboration with local partners and continues to form part of BP’s petrochemical business, demonstrates our ability to utilize our technologies as a competitive advantage when seeking opportunities to expand our position in foreign markets. We intend to continue to use our technological expertise to seek similar projects in regions with low-cost feedstock access or high growth, such as the Middle East and north Africa. In addition, we view technology licensing as an effective way of establishing our products in the market, as well as providing a stable contribution to our adjusted EBITDA of approximately $50 million to $75 million per year.
•	Experienced Management Team. We have a talented and experienced management team recruited from both within BP and externally. Our management team is led by Ralph Alexander, our Chief Executive Officer, who has worked in a variety of roles within BP, including as Chief Executive Officer of BP’s Gas, Power, and Renewables segment, as Group Vice President in BP’s Exploration and Production segment and its Refining and Marketing segment and, most recently, as Chief Executive Officer of BP’s Petrochemicals segment. Mr. Alexander is supported by a team of business and functional leaders, including Mark Tomkins, our Chief Financial Officer, who have extensive experience in petrochemicals, refining, supply and trading and who we believe have the requisite skill set to successfully execute our strategy. Mr. Tomkins has 15 years of experience with public chemical companies.

Strategy

      We believe we have an opportunity to significantly improve our competitive position and future financial performance by implementing the key components of our strategy, which are to:

•  Achieve Performance Improvement Through Our Accelerator Program and By Implementing a Simplified Organizational Structure. To reduce our operating costs and maximize our operating efficiency, we have embarked on a comprehensive performance improvement program, which we refer to

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as our Accelerator program. The actions we have identified under this program and intend to implement over the period from 2005 to 2007 are based on a detailed analysis of our operational performance relative to our peers in the petrochemical and refining industries, and encompass all of our global operations from procurement to manufacturing, sales, marketing and logistics, as well as overhead costs. Projects include eliminating unprofitable product lines, redesigning and enhancing our sales and marketing activities by optimizing channels of trade, reducing our overhead and functional costs commensurate with our status as a standalone petrochemical company and making targeted investments to maximize our asset utilization and productivity.

We are also taking a number of steps to ensure that the performance improvements we intend to achieve through our Accelerator program become a basis for continued action. Throughout our organization, we have reduced management and other organizational layers, focusing the business around three operating companies which are responsible for driving the performance of our overall business.

•  Maximize Cash Flow. We have revamped our incentive compensation programs for 2005 to focus every employee on a single financial goal, improving our adjusted EBITDA. In 2006, our incentive compensation programs will focus on three measures, adjusted EBITDA, capital expenditures and working capital, to further enhance the focus in our organization on delivering sustainable cash flow. Performance management systems are being put in place to allow employees to monitor the impact of their actions on our performance. We believe in a focused capital expenditure plan dedicated to attractive investment projects, as well as projects that maintain and improve our cost and technology positions. We intend to use our free cash flow to reduce indebtedness and selectively expand our businesses, particularly to access low-cost feedstocks and serve growth markets.

•  Enhance the Value of Our Portfolio. We intend to focus on businesses that we believe have the potential to maintain or achieve cost and market leadership positions. We plan to manage our assets and businesses to achieve strong unit cost and gross margin performance relative to competitive benchmarks and make a meaningful financial contribution to our company. We expect that as a result of our Accelerator program, the substantial majority of our assets and businesses will meet these benchmarks by 2007. In those cases where an asset or business is unable to meet these benchmarks, or where it would be uneconomical for us to implement the necessary improvements, we will consider selling or closing the relevant asset or business. This strategy has already led to the divestment of businesses and the closure or planned closure of certain assets in 2004 and 2005, including, for example, the sale of the BDO unit of our Lima, Ohio facility, the planned closure of the LAO facility in Pasadena, Texas in late 2005, and the planned merger of our European polystyrene and EPS business into a 50/50 joint venture with Nova Chemicals Corporation.

•  Expand Position in Locations with Low Cost Feedstocks. We intend to improve our long-term competitiveness by accessing low-cost feedstocks in the Middle East and north Africa through strategic collaborations with local partners and governments to build petrochemical complexes in these regions. In June 2005, we entered into a non-binding memorandum of understanding to construct a world-scale cracker and associated derivative complex in Saudi Arabia. Our goal is to sign a binding agreement and secure a guaranteed feedstock supply for the facility by year-end 2005 and commission the facility by 2009. We believe we are well-positioned to provide all of the technology, project management skills, operational experience and market positions needed to build, operate and market the products of world-scale petrochemical complexes. The successful completion of the SECCO facility in Shanghai, China, in which our employees played a significant part, is a recent example of this partnering approach. Investments in the Middle East or north Africa can further enhance our ability to serve the fast-growing Asian market from a low-cost base and serve as a platform for future long-term growth opportunities.

•  Maximize Profitability by Optimizing Supply and Trading Flows. We intend to continue to strengthen our supply and trading capabilities to ensure we derive maximum benefit from optimizing our operations, channels to market and market positions. The capabilities we have developed closely mirror the commercial model which BP has established and successfully operated in the oil and gas markets for many years. We believe this model distinguishes us from our peers in the petrochemical industry.

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Petrochemicals

Introduction

      In our petrochemical business, we produce olefins and a broad range of polymers and derivatives. The following table provides a breakdown of the revenues, adjusted EBITDA and total assets of each of the three segments included in our petrochemical business for the periods and as of the dates indicated:

								As of and for
		As of and for the year						the six months
		ended December 31,						ended June 30,
		2002		2003		2004		2004		2005
		($ in millions)
Revenues(1)
	O&P North America		2,341		2,698		3,680		1,615		2,150
	O&P Europe		4,863		5,609		7,424		3,328		4,399
	Global Derivatives		1,749		1,769		2,090		1,015		1,272
	Total		8,953		10,076		13,194		5,958		7,821
Adjusted EBITDA(2)
	O&P North America		91		171		257		77		250
	O&P Europe		148		54		334		195		492
	Global Derivatives		211		74		5		41		164
	Total		450		299		596		306		909
Total assets
	O&P North America				2,021		2,314				2,478
	O&P Europe				5,738		6,376				5,796
	Global Derivatives				1,790		1,520				1,639
	Total				9,549		10,210				9,913

(1)	Revenues exclude revenues from discontinued operations. See “Managements Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations” for more information on revenues from discontinued operations.
(2)	For more information on how we calculate adjusted EBITDA, see “Selected Combined Financial Data — Use of Non-GAAP Financial Measures.”

Products

Overview

      The following table provides an overview of our key petrochemical products along with their principal applications:

Key products			Principal applications
O&P
	Olefins and related products
		Ethylene	Polyethylene, polyvinyl chloride, ethylene oxide and styrene
		Propylene	Polypropylene, acrylonitrile and propylene oxide
		Butadiene	Synthetic rubbers and acrylonitrile butadiene styrene
		Benzene	Styrene, cumene and nylon
		Styrene	Polystyrene and acrylonitrile butadiene styrene, synthetic rubbers and certain polyesters

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Key products			Principal applications
	Polymers
		Polyethylene	Films for packaging, agricultural applications, molded products, pipes and coatings
		Polypropylene	Molded products, filaments, fibers and films
		Polystyrene	Food packaging and appliance/electrical housings
		Expandable polystyrene	Insulation and consumer packaging
	Solvents and industrial chemicals
		Synthetic ethanol	Solvent used in personal care products, inks, household chemicals and industrial applications
		Ethylene oxide and derivatives, including ethylene glycols	Polyester, antifreeze/coolants and industrial detergents
		Propylene oxide and derivatives, including propylene glycols	Polyurethane foam and polyester resins
Global Derivatives
		Acrylonitrile	Acrylic fibers and acrylonitrile butadiene styrene and styrene acrylonitrile polymers
		Linear alpha olefins	Comonomers for polyethylene, synthetic lubricants, detergents and oil drilling chemicals
		Poly alpha olefins	Synthetic lubricants
		Polyisobutylene	Additives, lubricants, sealants, shrink wrap, cables and adhesives

      The following table breaks down the total capacity of the facilities comprising our petrochemical business by each petrochemical product, including our pro rata shares of the capacity of facilities operated by joint ventures and the capacity of third-party facilities that provide us with products under various commercial agreements:

				Full-year
				capacity(1) as of
				June 30, 2005
				(Pounds in millions
				(mmlbs))
O&P
	Olefins and related products
		Ethylene			8,860
		Propylene			3,830
		Butadiene			1,000
		Benzene			1,540
		Styrene			1,820
	Polymers
		Polyethylene
			HDPE		4,780
			LDPE/ LLDPE		1,850
		Polypropylene			5,680
		Polystyrene
			Polystyrene		910
			EPS		360

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			Full-year
			capacity(1) as of
			June 30, 2005
			(Pounds in millions
			(mmlbs))
	Solvents and industrial chemicals
		Synthetic ethanol		560
		EO and derivatives		1,470
		PO and derivatives		620
	Other			1,000
Global Derivatives
	Nitriles
		Acrylonitrile		2,010
		Other nitriles		1,240
	Alpha olefins
		LAOs		2,180
		PAOs		310
	PIB			340
Total				40,360

(1)  Capacity is defined as nameplate capacity. See “— Manufacturing — Overview” for more information on how we calculate capacity.

     Our most important olefins in terms of production volumes are ethylene and propylene. Most of our production of these olefins is consumed internally in the manufacture of polymers. Our most important polymers in terms of production volumes are polyethylene and polypropylene. The products that made the largest contributions to our consolidated revenues in the three years ended December 31, 2004 were polyethylene and polypropylene.

O&P

Olefins and related products

      According to CMAI, measured by expected average annual capacity for 2005, we are the seventh largest manufacturer of ethylene globally. In Europe, we consume more ethylene than we produce. By contrast, our olefins crackers at our Chocolate Bayou facility manufacture substantially more ethylene than is needed by our polymers and derivatives units in the Gulf coast region. As a result, we sell substantial amounts of the ethylene we produce to customers in the Gulf coast region.

      According to CMAI, measured by expected average annual capacity for 2005, we are the ninth largest propylene manufacturer in the world. In both North America and Europe, we consume more propylene than we produce, primarily to produce polypropylene and acrylonitrile.

      According to CMAI, measured by expected average annual capacity for 2005, we are the seventh largest manufacturer of butadiene in the world. Since we have no internal use for the butadiene we manufacture in North America and Europe, our entire production is sold externally.

      In 2004, all of our benzene production volumes were manufactured in Europe and were primarily used to produce styrene, with the remainder sold externally.

      According to CMAI, measured by expected average annual capacity for 2005, we are the eighth largest manufacturer of styrene in the world. A portion of our styrene production in Europe is sourced from third parties based on long-term supply agreements. Because we have no polystyrene operations in North America, all of our North American styrene volumes are sold to external customers. In Europe, our entire styrene production is used in the manufacture of polystyrene, as discussed in greater detail below.

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Polymers

      According to CMAI, measured by expected average annual capacity for 2005, we are the fifth largest manufacturer of polyethylene, the third largest manufacturer of HDPE and the sixth largest manufacturer of LLDPE. In North America, the only type of polyethylene we make is HDPE. Our HDPE products in this region are targeted at three main markets: (1) durables, which comprise industrial applications, such as pipes, consumer applications, automotive applications, including car fuel systems, and building and construction applications, (2) packaging applications, such as organoleptic caps and closures (that is, caps and closures which do not affect flavor or odor), organoleptic blow-molded long-life milk bottles and other blow molded or injection-molded applications and (3) commodities, which are products where there is little scope for differentiation, such as novelty toys, disposable shopping bags and pails. In Europe, we manufacture LDPE, LLDPE and HDPE. Our European LLDPE production is primarily sold to customers in the film sector, while our LDPE products are primarily marketed to customers in the coatings sector. With respect to HDPE, we are a leader in a number of European markets that permit a significant scope for product differentiation. The applications targeted by us include markets for premium products such as pressure pipes, organoleptic caps and closures, organoleptic blow-molded long-life milk bottles and car fuel systems. We are also present in other commodity blow-molded and injection-molded applications.

      Our competitive position in the worldwide polyethylene markets is supported by our proprietary swing technology for the production of HDPE and LLDPE. See “— Research and Technology — Our Key Technologies” for more information on our various polyethylene manufacturing technologies.

      According to CMAI, measured by expected average annual capacity for 2005, we are the third largest polypropylene manufacturer in the world. In North America, we target our polypropylene products at similar markets as our HDPE products, including consumer and industrial durables, rigid and flexible packaging applications, and fiber and film applications. We believe this approach allows us to efficiently market our polymers through a common sales and marketing team. In Europe, our focus is on the fiber, film and rigid packaging sectors. In addition, we are a leading European supplier in the heat seal films market, which we believe offers significant scope for product differentiation. Our competitive position in the polypropylene markets is supported by our proprietary technology for the production of polypropylene. See “— Research and Technology — Our Key Technologies” for more information on our polypropylene manufacturing technology.

      According to CMAI, measured by expected average annual capacity for 2005, we are the sixth largest producer of polystyrene in the world. In May 2005, we signed an agreement with NOVA to combine our and NOVA’s European polystyrene and EPS businesses in a 50/50 joint venture, to be called NOVA Innovene, which we believe will substantially strengthen our competitive position in the polystyrene and EPS markets in Europe.

Solvents and industrial chemicals

      We make several solvents and industrial chemicals, including EO, EG, PO and PG. We primarily sell our EO products to third party manufacturers and use the balance to produce EG, glycol ethers and esters and ethanolamines. Our most important solvent is synthetic ethanol. According to CMAI, measured by expected average annual capacity for 2005, we are the second largest provider of synthetic ethanol in the world. Given the high level of purity of our synthetic ethanol compared with fermentation ethanol, we market this product to the cosmetics and pharmaceuticals sectors.

Global Derivatives

Nitriles

      Our main product in the nitriles sector is acrylonitrile. We also make acetonitrile and hydrogen cyanide, which are specialty nitriles that are derived as co-products of acrylonitrile. According to CMAI, measured by expected average annual capacity for 2005, we are the largest manufacturer of acrylonitrile in the world. The primary applications for acrylonitrile are acrylic fiber and ABS plastics. We have the capability to purify our own acetonitrile and can also purchase and purify crude acetonitrile from other companies which do not have the necessary purification equipment. The resulting purified acetonitrile is primarily marketed as a solvent for

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pharmaceutical applications. Hydrogen cyanide, the other co-product derived in the acrylonitrile production process, is an extremely hazardous gas used mainly to manufacture polymers (coatings and nylon) and for chemicals used in gold extraction. We have developed significant safeguards to ensure the safe handling of our nitriles, including the use of specially designed railcars and pipelines for transportation to nearby customers. We believe that our leading market position is a result of the fact that our acrylonitrile production process and the catalysts we use in that process are the leading acrylonitrile production technology in the world. See “— Research and Technology — Our Key Technologies” for more information on our acrylonitrile manufacturing technology.

Alpha olefins

      Measured by expected average annual capacity for 2005, we are among the largest suppliers of LAOs and PAOs worldwide. As a “full-range” LAO producer, we manufacture a whole range of LAOs and, accordingly, must sell our LAO production in the proportions yielded by our facilities. This exposure often creates commercial challenges, as different segments of the LAO market tend to grow at different rates. We benefit from the fact that our technology provides us with a certain amount of flexibility in adjusting our yield slate, thereby emphasizing certain products and deemphasizing others. However, our technology is not an “on-purpose” or “single product” technology that would permit us to manufacture only specific types of LAOs.

Other

      In Europe, we operate units that make nitrogen products such as ammonia and nitric acid. We also make PIB. According to CMAI, measured by expected average annual capacity for 2005, we are the largest supplier of PIB in the world.

Manufacturing

Overview

      We believe that the manufacturing operations of our petrochemical business benefit from the large scale of our key sites, a high degree of integration and proprietary process technologies. Our petrochemical facilities are located in North America and Europe. Our key assets include the following:

•  our Chocolate Bayou, Texas facility, which comprises one of the largest cracker installations in North America, and our Battleground, Texas, facility, which is one of the largest North American HDPE facilities and is integrated with our Chocolate Bayou site through a pipeline system owned by us; and

•  our three large petrochemical facilities in Cologne, Germany, Grangemouth, United Kingdom, and Lavéra, France, of which the latter two are fully integrated with onsite refineries, plus a number of market-facing facilities which are located in close proximity to our customers.

      All of our olefins crackers are either co-located with, or connected by pipeline to, polymers and derivatives units, enabling us to realize economies of scale, improve our facilities’ energy management and minimize logistics costs. In addition, two of our European crackers are integrated with onsite refineries, allowing further hydrocarbon optimization. We believe that the global reach of our operations enables us to optimize our production across different regions. Our focus has been on increasing the size and efficiency of our crackers and preparing them for compliance with new environmental laws and regulations and expanding and improving our polyethylene and polypropylene assets by replacing less efficient units with new installations. We believe these investments have positioned us well to participate in the current upswing of the petrochemical cycle. In addition, on June 8, 2005, we entered into a nonbinding memorandum of understanding to construct a world-scale cracker and associated derivative complex in Saudi Arabia. Our goal is to sign a binding agreement by year-end 2005, secure a guaranteed feedstock supply for the facility by year-end 2005 and commission the facility towards the end of 2008 or early in 2009. We believe that this constitutes an attractive investment opportunity due to the significant reserves of low-cost gas reserves available in the Middle East. See “— Facilities” for more information on our facilities, “— Research and Technology” for more information on our proprietary process technologies and “— Joint Ventures” for more information on our joint ventures.

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      The size of our manufacturing operations has grown in recent years, both through organic growth and as a result of acquisitions. Our most significant acquisitions were our purchase in 2001 of Bayer’s 50% stake in Erdölchemie GmbH, a joint venture which operated our Cologne site, our acquisition of Solvay’s polypropylene businesses and the formation of two HDPE joint ventures between us and Solvay in 2001 and our acquisitions of Solvay’s interests in these joint ventures in January 2005. We believe that the growth of our business has opened up significant opportunities for efficiency gains and for streamlining our operations as we integrate the acquired assets into our existing organization.

      The following table sets forth the total capacity of the production facilities of our petrochemical business, including our pro rata shares of the capacity of facilities operated by joint ventures and the capacity of third-party facilities that provide us with products under various commercial agreements:

	Average capacity(1)		Full-year
	for the year ended		capacity(1) as of
	December 31,		June 30,
	2004		2005
	(mmlbs)		(mmlbs)
North America		13,680		14,430
Europe		24,850		25,930
Total		38,530		40,360

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(1)  Capacity is defined as nameplate capacity, which is calculated as the result of (1) the aggregate MSDR for all of our facilities multiplied by the actual number of days in the period for which the calculation is made, minus (2) on an average annual basis, the expected amount of volumes expected to be lost due to reliability constraints inherent in the operation of a facility, scheduled turnarounds and transition products. Transition products result when a production unit is adjusted to change product grades, typically in response to customer requirements. Because such adjustments are made while the unit is up and running, it may temporarily yield products which do not fit within a specific grade level. For each facility, the MSDR is calculated by dividing the highest monthly production volumes ever achieved by that facility by the number of days in the month in which those volumes were achieved, subject to adjustment in the event that the facility was unable to operate at its full potential in the relevant month. Capacity figures are reviewed annually for each facility and typically adjusted upwards each year due to upgrades or expansions. We believe it is appropriate to exclude from capacity figures production volumes expected to be lost due to anticipated manufacturing constraints in order to give a more realistic picture of the volumes we are able to achieve. However, you should be aware that there is no uniform definition of capacity in the petrochemical industry, and other companies may define capacity differently than we do.

     In 2004, our petrochemical facilities operated on average at 88% of their capacity. The main reason why our facilities’ utilization is less than their capacity is that we periodically adjust our production volumes in response to changes in the consumption of our petrochemical products and variations in feedstock and product prices. Our facilities’ utilization is also affected by unexpected outages due to unforeseen reliability problems and unscheduled turnarounds.

      As described in greater detail in the regional discussion below, we faced major reliability problems at several sites in 2000 and 2001, mainly affecting our crackers. We began to address these issues through targeted investments in our plants and infrastructure, workforce assessment and development programs and process automation. Since 2001, these initiatives have led to significant improvements in the reliability of our assets, particularly our olefins crackers and refineries. However, issues remain with respect to some of our assets, in particular some of our polymers and derivatives units. We intend to build on the initial improvements we achieved in 2002 and focus our efforts on those assets with respect to which we continue to have reliability issues. Moreover, we plan to improve the reliability of our assets with remediation measures as part of our ongoing performance improvement program. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Key Factors Driving Our Results — Asset utilization, reliability and turnarounds” for more information on the reliability of our assets.

      Turnarounds are outages of a unit scheduled to carry out necessary inspections and testing to comply with industry regulations. These outages also permit us to perform any additional maintenance activities that may be necessary. Where possible, we seek to schedule the timing of turnarounds to coincide with periods of relatively low demand for the products of the relevant unit. Olefins crackers typically undergo major turnarounds every four to five years, with each turnaround lasting four to six weeks. Polymers and derivatives units are subject to more frequent maintenance shutdowns, typically one turnaround every one or two years, but each of them lasts only seven to ten days.

      We have recently implemented a new managerial structure which we believe will assist us in improving the utilization of our facilities. Historically, we have managed our petrochemical business by product line. As a result, it was not uncommon for different units at the same site to be under different management. In some cases, this has resulted in conflicting maintenance strategies and a lack of focus on shared infrastructure. We have recently installed a single point of accountability at each of our sites. We believe that this change has resulted in a simplified, integrated management structure that will enable us to identify synergies and manage our sites accordingly. In addition, we expect that our ongoing efforts to simplify our product portfolio will enable us to minimize losses from transition products. By focusing on those products which generate the highest profits, we believe we will be able to increase utilization rates and create incremental margin opportunities.

North America

      In North America, our petrochemical business comprises eleven sites including our major facilities in Chocolate Bayou, Texas, and Battleground, Texas. In 2004, these facilities had total production volumes of 12,170 mmlbs.

      Chocolate Bayou is our largest site in North America. In 2001, several furnaces of one of the facility’s crackers were destroyed due to an offsite power surge combined with the failure of certain control technologies.

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Following this incident, we rebuilt the destroyed furnaces and initiated a program to modernize the facility to improve the cracker’s availability and reliability. As a result, the facility’s reliability increased from 83% in 2001 to 98% in 2002 and remained relatively constant in 2003 and 2004. However, on August 10, 2005, we experienced a fire at one of the facility’s crackers, which will result in a loss of some of our olefins production volumes for 2005.

      In May 2005, we completed the DCP, a program involving investments of $337 million over a period of several years, to increase the Chocolate Bayou facility’s ethylene capacity by approximately 650 mmlbs and improve its efficiency and to meet new environmental laws and regulations. As a result, Chocolate Bayou now has one of the largest cracker installations in the region. Its central location in the Gulf coast area and access to pipeline and storage facilities permit the site to place its surplus ethylene either directly in the local merchant market or in storage to bridge time lags between production and consumption. We expect that the scale of the crackers will also enable us to better leverage the facility’s infrastructure and work force. Another key strength of the facility is the crackers’ flexible design. While their main feedstock is gas, which is obtained from various sources, including our gas fractionator near Hobbs, New Mexico, the commodity markets and BP’s refinery in Texas City, Texas, the facility also has the ability to process naphtha. This flexibility enables us to manage our feedstock mix in response to changes in economic and market conditions. All of our polymers and derivatives facilities in North America are either connected with the Chocolate Bayou crackers or are adjacent to facilities operated by BP or third parties with whom we have feedstock arrangements.

      Among our North American polymers and derivatives sites, our key facility is our Battleground, Texas, site, which is one of the largest HDPE complexes in North America. Battleground is integrated with Chocolate Bayou by way of a pipeline system owned by us. Our manufacturing assets in this region also include several major global derivatives facilities, principally Green Lake, Texas, Joffre, Canada, and Lima, Ohio. Measured by capacity, Green Lake is the largest facility for acrylonitrile and related products in the world. Joffre is one of the newest LAO units in the world and has access to low-cost third party ethylene feedstock derived from Canadian gas. Lima is an integrated nitriles complex, producing acrylonitrile and related products, with access to feedstock from an adjacent refinery. Lima also manufactures acrylonitrile catalysts for other facilities on a global basis. Our facilities in Carson, California, Texas City, Texas, and Whiting, Indiana, are operated by our onsite management teams in cooperation with employees from the respective adjacent BP refineries. The facility in Cedar Bayou, Texas, is operated by Chevron Phillips in a 50/50 joint venture between us and Chevron Phillips.

      Historically, we have also operated many sites that were significantly smaller and less efficient. Our strategy is to gradually replace or modernize these facilities. For example, in March 2005, we sold the BDO unit at our Lima, Ohio, facility. Furthermore, we intend to close down the LAO facility in Pasadena, Texas, which BP currently operates for us under a toll manufacturing agreement, in late 2005.

Europe

      In Europe, we own and operate three major cracker complexes, one in Cologne, Germany, one in Grangemouth, United Kingdom, and one in Lavéra, France. Each of these sites includes polymers and derivatives units, and the Grangemouth and Lavéra facilities are also integrated with refineries. The Lavéra facility consists of a combination of units fully owned by us and various 50/50 joint ventures between us and Total. These joint ventures operate their respective units within the Lavéra facility. We also own and operate several standalone polyethylene and polypropylene plants at our sites in Lillo, Belgium, Geel, Belgium, Sarralbe, France, and Rosignano, Italy. In addition, we own and operate a standalone styrene, polystyrene and EPS plant at our Marl, Germany, facility and a polysterene and EPS plant at our Trelleborg, Sweden, facility. In 2004, our European facilities had production volumes of 21,720 mmlbs.

      In May 2005, we signed an agreement with NOVA to combine our and NOVA’s European polystyrene and EPS businesses in a 50/50 joint venture, to be called NOVA Innovene, which we believe will substantially strengthen our competitive position in the polystyrene and EPS markets. We expect to commence operations under the joint venture, pending regulatory and other approvals, in the third quarter of 2005. The joint venture will be headquartered in Fribourg, Switzerland, and will include six manufacturing facilities in France, Germany, The Netherlands, Sweden and the United Kingdom. We will contribute our polystyrene and EPS production

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facilities in Marl, Germany and our polystyrene production facilities in Trelleborg, Sweden. BP’s polystyrene and EPS facility in Wingles, France, may be transferred to the joint venture in 2007 if put or call options provided for in the agreements relating to the formation of the joint venture are exercised. The joint venture will enter into a commercial agreement with BP under which the joint venture will supply feedstock to, and purchase and distribute all of the production of, the Wingles facility. We have retained full ownership of our styrene operations. NOVA will contribute four polystyrene and EPS production facilities in The Netherlands, France, and the United Kingdom to the joint venture. We expect to account for the joint venture under the equity method.

      The key strength of our operations in Europe is the high degree of upstream infrastructure integration between our crackers and their feedstock sources. In the case of Grangemouth and Lavéra, our crackers are physically integrated with refineries located on the same site. This integration allows us to leverage the sites’ infrastructure, energy management and work force and realize feedstock synergies in both directions. For example, each of the refineries provides the associated petrochemical plant with naphtha, LPG, butanes and propylene and in return receives pygas, which is a gasoline blending component, and hydrogen. Moreover, because each of these crackers and the respective refineries share a single site, we incur virtually no transportation costs in connection with moving petrochemical feedstock from the refinery into the cracker complex. Grangemouth is connected with the Forties Pipeline System (FPS), which carries oil from a variety of North Sea fields, and BP’s oil and gas processing complex at Kinneil, Scotland, which separates the associated gas from the oil carried through the FPS and delivers it directly into the petrochemical facility. Although our cracker complex in Cologne, Germany is not co-located with a refinery, it is located in the center of one of the key industrial regions of Germany and has access by pipeline and ship to the Rotterdam area in The Netherlands, one of the world’s most competitive naphtha supply regions. It also benefits from a balanced polymers and derivatives portfolio behind a large and reliable olefins cracker. Cologne also has the ability to sell its excess ethylene to buyers in the merchant market through the ethylene pipeline owned by ARG. ARG is a company owned by BP and five other European petrochemical companies. BP is in the process of transferring its stake in the ARG ethylene pipeline to us. In the future, the Cologne facility will also have access to the propylene pipeline owned by the European Pipeline Development Company, in which we own a stake.

      Our Grangemouth and Lavéra sites have historically suffered from reliability issues. In 2000 and 2001, both sites experienced mechanical breakdowns, utility failures and fires at both sites, although these issues primarily affected Grangemouth. In the case of Grangemouth, these incidents culminated in a government inspection and the imposition of fines. We have made significant investments in both sites, and we believe that these investments have resulted in better reliability. We expect further improvements in the future as we continue to make appropriate investments. The reliability of the petrochemical units at Grangemouth was 81% in 2001, 91% in 2002, 90% in 2003 and 90% in 2004, while the reliability of the petrochemical units at our Lavéra site was 90% in 2001, 94% in 2002, 93% in 2003 and 94% in 2004. Our Cologne site has consistently achieved significantly higher reliability rates during this period.

      We also have four large standalone polyethylene and polypropylene sites in Lillo, Geel, Sarralbe and Rosignano. While these sites are not integrated with crackers, Lillo, Geel and Sarralbe are connected to olefins pipelines and Rosignano imports ethylene by ship, providing each of these facilities with flexibility in sourcing their feedstock. Moreover, all of these sites are located in close proximity to their customers.

      We have also made significant investments in our facilities, particularly at our Grangemouth site. In 2000, we commissioned a new polypropylene unit and a new LLDPE unit and converted one of the existing LLDPE units into an HDPE unit. In 2001, we expanded the capacity of the gas cracker. In 2002, we commissioned a new synthetic ethanol plant. In addition, we commissioned a new HDPE unit at our facility in Lillo in 2002. At our Lavéra site, we focused mainly on de-bottlenecking our existing units. Since these investments were made, we have continued to upgrade our facilities. In 2004, we improved the reliability of the LLDPE unit we commissioned at Grangemouth in 2000 by upgrading its catalyst. We have also taken a series of steps to rationalize our European polymers and derivatives units, including by closing two inefficient HDPE lines at Grangemouth in 2003 and 2005.

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Raw Materials and Energy

      The primary raw materials of our petrochemical business are the basic feedstocks of our olefins crackers, naphtha and gas. Consistent with the industry, our principal cracker feedstock in North America is gas, whereas our European crackers primarily process naphtha. In aggregate, our most important feedstock is naphtha, reflecting the weighting of our asset base towards Europe. A portion of our European crackers’ naphtha requirements is sourced from our refineries in Grangemouth, United Kingdom, and Lavéra, France.

      The vast majority of our crackers’ production is consumed as feedstock by our polymers and derivatives units. However, the olefins supplied by our crackers are not sufficient to match the overall requirements of our polymers and derivatives units. While we have an ethylene surplus in North America, in Europe the situation is reversed and we consume more ethylene than we produce. In addition, we have a propylene deficit in both regions. In Europe, these shortages are due to the fact that many of our European sites comprise polymers and derivatives units that are not integrated with onsite olefins crackers. In North America, our propylene shortage is in part a result of the fact that the principal feedstock of most North American crackers, including our crackers at Chocolate Bayou, is gas, and that gas-fed crackers yield substantially less propylene than crackers processing naphtha. It is also a legacy of the fact that when we were a part of BP our crackers were integrated with BP’s refineries and processed BP’s surplus refinery propylene. To redress our olefins shortage, we purchase ethylene and propylene on the merchant market through supply contracts and swaps with other petrochemical and refining companies, including BP.

      Overall, BP is our single most important external supplier of naphtha and gas. Although most of our external feedstock supplies are available from a variety of third parties, some of our sites are substantially reliant on BP refineries. For example, our facilities in Carson, California and Texas City, Texas depend on raw materials from the respective BP refineries located on the same sites and have no convenient access to alternative supply channels. We plan to make investments at Texas City to allow us to access the commodity markets if we choose to do so and import benzene from the U.S. Gulf coast merchant market. The substantial majority of the petrochemical feedstocks we obtain from BP are provided to us under various Hydrocarbon Sale and Purchase Agreements with varying durations. See “Certain Relationships and Related Transactions — Commercial Interface Agreements — Hydrocarbons Sale and Purchase Agreements” for a description of these agreements.

      We also obtain a substantial proportion of our feedstock requirements on the commodity markets. BP assists us and will continue to assist us in making and optimizing feedstock purchases of naphtha and gas on the commodity markets under various Master Services Agreements, which may be terminated by either party with notice periods ranging from three to twelve months, provided that no notice may be given prior to December 31, 2005. We expect to eventually carry out some or all of this commodity trading and related hedging ourselves and have entered into transitional arrangements with BP which provide for the training of our staff and the transfer of knowledge with a view to enabling us to develop these functions within our organization. See “Certain Relationships and Related Transactions — Commercial Interface Agreements — Supply and Trading Agreements — Master Services Agreements” for a description of these agreements.

      The costs of the feedstocks we require to make our petrochemical products (naphtha, ethane, butane and propane) are principally driven by the price of oil and natural gas. In the current environment of relatively high oil prices, crackers located in the Middle East enjoy the advantage of access to low-cost gas feedstock.

      Although energy is generated at several of our sites, including as part of petrochemical manufacturing processes, we are a significant net purchaser of both electricity and gas. Typically we procure our requirements from local producers or utilities at local market prices.

Transportation

      We have access to a comprehensive transportation network and associated logistics infrastructure through a combination of ownership and long-term contracts. This network allows us to move feedstocks and products at competitive rates and provides us with access to the merchant market, enabling us to manage demand and supply imbalances across the petrochemical value chain in response to market conditions.

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      Our transportation modes include pipelines, ship, rail and road. The choice of transportation mode depends on the local infrastructure and geography and the physical properties of the product or feedstock being transported.

      Because pipelines are the most efficient and least expensive mode of transportation, we consider them to be of strategic importance. Some of the pipelines we use are owned by us, while others are consortium-owned pipelines in which we hold a stake or are provided to us by dedicated operators under long-term contracts. Rules and conventions governing pipeline ownership vary substantially between North America and Europe, as does the regulatory framework governing the setting of transportation tariffs.

      Where we are reliant on access to shipping channels, we either own or hold stakes in the relevant terminals and storage facilities or have secured access to them through long-term contracts. However, we do not own any of the ships we use and instead rely on an extensive network of third party shipping companies which make capacity available to us on a spot or term contract basis.

      BP will for a limited period provide us with shipping and global assurance services under various agreements. We expect that, when these agreements expire, we will have built sufficient in-house capability to carry out the relevant services ourselves.

Sales and Marketing

      We have structured our sales and marketing organization to match the sector and regional requirements of our customers. Each sales team is led by a sales manager focusing on a particular product or market sector. In addition, each team includes sector and regional key account managers who are responsible for our largest customers in the relevant region, account managers focusing on smaller customers in specific countries and sales executives working at customer service centers located at our sales offices. In light of the specialized nature of our petrochemical products, we ensure that our sales force possesses appropriate technical knowledge of our products and their applications. In Europe, we use a separate sales organization to market those products in our HDPE and polypropylene portfolio which are more differentiated. Those of our customers who are not serviced through one of our sales offices are supplied through a network of third party distributors. We also maintain a network of agents, particularly in countries for which we do not have direct sales teams. We remunerate these agents on a commission basis.

      A critical element of our sales and marketing approach is to assist our customers in optimizing the use of our products in their internal processes. Our dedicated technical service teams work closely with our sales force and are available to our customers for advice and support. They also provide a critical link between our sales and marketing personnel and our product development and manufacturing staff. We believe that the extensive market knowledge and industry experience of our sales and marketing teams, our focus on technical support and our strong emphasis on customer satisfaction have helped us establish and maintain long-term customer relationships.

      In order to ensure that we are in a position to meet our customers’ rapid delivery requirements, we carry inventories of finished products at our facilities and distribution centers.

      We have approximately 2,700 customers worldwide. Our industrial customers include a large number of companies in a variety of downstream industries involving rigid packaging, fibers, flexible packaging and chemical intermediates. For more information on the product markets served by us, see “— Products.” No single customer accounts for more than 5% of our revenues.

      Most of our sales are to customers in the merchant market and are made on contract or spot terms. These terms allow us to reset prices at regular intervals, typically monthly or quarterly, to reflect changes in market prices. Some contracts are based on negotiated prices, while others are based on pricing formulas or refer to spot market rates.

      Although our production facilities are located in Europe and North America, we also ship significant quantities of our products to Asia for sale in that region. We have an established regional office in Shanghai, China to manage our operations in Asia.

      In China, our current business license does not permit us to make local sales of product directly to customers in local currency. Instead, we work with our customers and distributors who take title to our products offshore

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and clear customs on their own. As part of the conditions under which China gained entry to the World Trade Organization, new regulations came into effect in December 2004 that permit foreign companies to import and export products and engage in wholesale activities and distribution within China. These new regulations are in the process of being implemented. We intend to apply to the Chinese authorities later in 2005 for a license that would include import, export, wholesale and distribution rights. However, there can be no assurance as to whether and when we will be able to obtain such a license.

Research and Technology

Overview

      We consider R&T to be a key element of both the short-term performance and the long-term growth of our petrochemical business. By investing in R&T, we seek to:

•  decrease our production costs with a view to increasing the margins we achieve in the manufacture and sale of our products;

•  make better products in order to increase our market share; and

•  reduce our capital expenditures to minimize the investments necessary to meet demand.

      In 2002, 2003 and 2004, we had research and development expenses of approximately $120 million, $115 million and $137 million, respectively. Our formation as a separate legal entity within the BP group and the integration of Solvay’s HDPE-related research projects in our own R&T program will allow us to rationalize our R&T activities with respect to polymers in North America and to integrate R&T teams in Europe which have worked separately. These steps have enabled us to improve the focus of our R&T activities and to reduce the overall level of our research and development expenses.

      We operate three principal R&T centers, one in Neder-over-Heembeek, Belgium, one in Naperville, Illinois, and one at our Battleground, Texas, facility. We also maintain pilot plant facilities at a number of sites, including Lavéra, France, Grangemouth, United Kingdom, and Rosignano, Italy.

      A substantial portion of our R&T expenditures in any given period is dedicated to the continuous improvement of our existing processes, products, assets and operations and is intended to yield returns in less than two years. This R&T work is carried out by a combination of integrated teams based at our facilities and centrally located specialists and research teams in one of our R&T centers. In addition, we allocate a portion of our R&T budget to longer-term projects targeted at more fundamental improvements, which we typically intend to yield returns within two to five years. We seek to protect our process technologies and products by seeking patents or retaining them as trade secrets.

      The market position of our petrochemical business is supported by a range of technologies. Among them are the following four highly competitive proprietary process technologies:

•  our gas phase polyethylene technology;

•  our gas phase polypropylene technology;

•  our slurry HDPE technology; and

•  our acrylonitrile technology.

      The four technologies listed above are the primary focus of our R&T efforts. Together, they form one of the most comprehensive technology packages available in the petrochemical industry. We use these technologies in our own production processes and also license them to external customers. We view technology licensing as an effective way of establishing our products in the market and of generating additional income. In addition, we believe that the ability to offer a comprehensive technology package is a substantial advantage in attracting joint venture partners for investments in regions characterized by low feedstock costs or high growth, such as the Middle East, north Africa, Russia and China.

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      We believe that the quality of our scientific staff is important to our success. The employees working in our R&T centers have comprehensive expertise in a variety of areas, including catalysis, process development, product and material science, modeling and project management. When we form teams for R&T projects, we seek to ensure that each team has both technical and commercial expertise. We consistently aim to improve the effectiveness of our R&T efforts by targeting our projects at the most valuable applications and using project management tools to monitor progress. At April 1, 2005, 659 of our employees — about 8% of our petrochemical workforce — worked in R&T functions. To attract and retain the best-qualified scientists and develop a high level of capability and competence in the key areas of processes, products and operations, we offer our employees challenging development opportunities and a competitive compensation package.

      In addition, we draw on external resources to enhance the scope, depth and effectiveness of our internal R&T efforts. We proactively seek mutually beneficial partnerships with third parties, including other petrochemical companies and leading universities. For example, we have a partnership with NOVA, which has led to the development of substantially improved catalysts for our gas phase polyethylene technology.

Our key technologies

Gas phase polyethylene technology

      Our proprietary gas phase polyethylene technology is designed to serve the LLDPE and HDPE markets, which are the fastest growing segments of the commodity polyethylene markets. The technology is characterized by low capital investments, low operating costs, low emissions and waste, and the fact that it does not require the use of additional solvents. It is known as a swing technology because it allows both LLDPE and HDPE to be produced from a single reactor, thereby permitting the manufacture of a broad range of products. We have licensed our technology to 25 petrochemical companies in more than 15 countries. According to Nexant, in 2004 the technology was used in 15% of the worldwide LLDPE/ HDPE capacity, second only to the polyethylene technology offered by Univation Technologies.

      Our technology uses our proprietary Ziegler-Natta catalysts. We use these catalysts internally and also sell them to external customers. We constantly improve our existing catalysts and seek to develop new ones, both alone and in collaboration with third parties. For example, we are currently in the process of expanding the reach of our gas phase polyethylene technology by commercializing products from our proprietary metallocene catalysts. These catalysts allow the cost-effective manufacture of LLDPE products with better strength and clarity characteristics compared with traditional Ziegler-Natta and chromium-based catalysts.

Gas phase polypropylene technology

      Our gas phase polypropylene technology is recognized in the industry as offering low capital investments and low operating cost. The design of our technology enables the cost-effective production of high-performance polypropylene plastics. In addition, the simplicity of the equipment used with this technology combined with our proprietary catalysts allows us to achieve very high reliability. We have licensed the technology to eight companies. According to Nexant, our technology accounted for 13% of the 24 mmlbs in capacity added by the industry between 2000 and 2005. Overall, it accounted for 7% of the worldwide polypropylene capacity in 2004. We intend to continue to improve this technology through a combination of process improvements, the development of new catalysts and engineering design work.

HDPE technology

      In addition to our gas phase technologies, we own a specialized technology for the manufacture of HDPE, which we acquired from Solvay. This technology is based on a slurry production process and is characterized by low capital investments and low operating costs. The technology may be used in combination with either a Ziegler-Natta catalyst or a chromium-based catalyst to make a range of superior products. It is particularly well-adapted to the manufacture of high-performance materials such as high pressure pipe, one of the fastest growing segments of the HDPE market, and one in which we hold a leading position. From both a cost and product perspective, we believe that our production technology is the leading HDPE technology available on the market, and we plan to license it selectively.

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Acrylonitrile technology

      Our main technology assets in the derivatives area are our proprietary fluid bed acrylonitrile process and related catalysts. Our technology is based on a chemical process for the transformation of propylene into acrylonitrile called ammoxidation. We have provided five generations of acrylonitrile catalysts, and there is continuing industry demand for these catalysts. Our technology is the leading nitriles manufacturing technology and, according to Nexant, it is used in more than 90% of the world’s acrylonitrile production. We continue to invest in acrylonitrile R&T to further improve the catalysts and maintain our competitive position.

Intellectual property

      Our policy is to protect all of our significant technologies by seeking patents, retaining it in the form of trade secrets, and defending and enforcing our intellectual property rights, where appropriate. We expect that this strategy allows us to preserve the advantages of the products we sell and the technologies we use and license, and helps us to maximize the return on our investment in research and development. We own, or have rights to, approximately 6,200 patents, divided into 650 patent families, in the United States, Europe and various other regions. In 2004, we filed 61 applications for new patent families. To protect confidential technical information which is not subject to patent protection, we rely on trade secret law and frequently enter into confidentiality agreements with our employees, customers and partners.

      While our patents and trade secrets constitute valuable assets, we do not view any one of them as being material to our operations as a whole. Instead, we believe it is the combination of our patents and trade secrets that creates advantages for our business.

      In addition to our own patents and trade secrets, we are party to licensing and other agreements authorizing us to use patents, trade secrets, confidential technical information and related technology owned by third parties and/or operate within the scope of patents owned by third parties.

      In addition, we own a number of registered trademarks, including our Innovene® brand. We continuously develop new names for new products, secure trademark protection for them, police our existing trademarks and enforce our legal entitlements in situations where third parties infringe upon any of these rights.

      In connection with our separation from BP, BP has transferred to us certain intellectual property rights and assets we require to operate our petrochemical business and our gas fractionator near Hobbs, New Mexico, pursuant to an Intellectual Property and Information Technology Separation Agreement. There are also certain technologies and associated intellectual property in which both we and BP have a common interest. In these cases, we or BP, as the case may be, have granted the other party licenses in a series of Common Interest Intellectual Property Agreements to ensure that both parties have specified access to such intellectual property and technology. See “Certain Relationships and Related Transactions — Reorganization Agreements  — Intellectual Property and Information Technology Separation Agreement” for more information regarding these agreements.

Competition

      We face intense competition in all petrochemical markets in which we compete. The main competitive criterion is price. In certain segments of the HDPE and polypropylene markets, where products must satisfy specified technical performance criteria, competition is also based on performance, quality and customer service. Given that most of our products are commodities, a key component of our competitive position is our ability to manage our costs successfully, requiring continuous management focus on reducing unit costs and improving efficiency. The main drivers in this respect are technology, scale, feedstock access, asset utilization, logistics and the ability to execute capital projects efficiently. We believe we are well-positioned with respect to each of these criteria.

      Our competitors vary in terms of the degree to which they are integrated with their feedstock sources. Companies like Dow Chemical Company (Dow Chemical), Borealis A/ S (Borealis) and NOVA have no refineries of their own. Companies like Chevron Phillips, Basell, N.V. (Basell) and Lyondell Chemical Company, including its Equistar operations (Lyondell/ Equistar), benefit from some degree of refinery integration resulting from

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relationships with their current or former parent companies or joint venture partners. Companies such as ExxonMobil Corporation (ExxonMobil), Royal Dutch/ Shell Group (Shell) and Total are fully integrated energy companies with deep integration between refining and olefins crackers.

      The principal competitors of our petrochemical business are Basell, Borealis, Chevron Phillips, China Petroleum and Chemical Corporation (Sinopec), Dow Chemical, ExxonMobil, Lyondell/Equistar, NOVA, Saudi Basic Industries Corporation (Sabic), Shell and Total. Several of our competitors, including Iran’s National Petrochemical Company, Saudi Arabia’s Sabic and China’s Sinopec, are fully or partially state-owned and could have broader goals than maximizing their profits, such as investing in the economies of their respective countries and providing local employment. In China, we also compete with Sino-foreign joint ventures, some of which are partnered by the competitors discussed above, and a variety of Asian importers. Most of our competitors market their products in North America, Europe and Asia.

      According to CMAI, measured by expected average annual capacity for 2005, we are the seventh largest manufacturer of ethylene, the ninth largest manufacturer of propylene, the fifth largest manufacturer of polyethylene and the third largest manufacturer of polypropylene in the world. The following table provides an overview of the market position of the principal competitors of our petrochemical business, measured by expected average annual capacity for these products in 2005:

Competitor	Market position(1)
Basell	Polyethylene (8th), polypropylene (1st)
Borealis	Polyethylene (10th), polypropylene (7th)
Chevron Phillips	Ethylene (8th), polyethylene (6th)
Dow Chemical	Ethylene (1st), propylene (4th), polyethylene (1st) polypropylene (10th)
ExxonMobil	Ethylene (2nd), propylene (1st), polyethylene (2nd), polypropylene (5th)
Lyondell/ Equistar	Ethylene (5th), propylene (6th), polyethylene (7th)
NOVA	Ethylene (11th)
Sabic	Ethylene (3rd), polyethylene (3rd), polypropylene (6th)
Shell	Ethylene (4th), propylene (2nd)
Sinopec	Ethylene (6th), propylene (5th), polyethylene (4th), polypropylene (2nd)
Total	Ethylene (9th), propylene (3rd), polyethylene (9th) polypropylene (4th)

(1)  According to CMAI data as of July 2005.

     Our global derivatives business operates in a relatively mature market environment. Royal Dutch, Chevron Phillips and Sasol Limited are our main competitors with respect to LAOs. Although there are numerous manufacturers of acrylonitrile, we are the largest producer in the world. In addition, more than 90% of the world’s acrylonitrile volumes are based on our process technology. Our most significant competitor is Asahi Kasei Corporation, which is the market leader in Asia. Other competitors include E.I. du Pont de Nemours and Company and Solutia, Inc. in North America and Koninklijke DSM N.V. in Europe.

Facilities

      Some of our facilities are located on sites wholly-owned by us, while others are located at sites which we share with other parties, including BP. As part of our separation from BP, we have entered into agreements to establish rules and procedures to facilitate operations at shared sites. See “Certain Relationships and Related Transactions — Commercial Interface Agreements — Site Cooperation Agreements” for a description of these agreements.

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      The following table sets forth the location, primary products and capacity of the major facilities in our petrochemical business, including our pro rata shares of the capacity of facilities operated by joint ventures:

		Full-year
		capacity(1) as of
Location	Primary products	June 30, 2005
		(mmlbs)
Battleground, Texas	HDPE, polypropylene		2,560
Chocolate Bayou, Texas(2)	Ethylene, propylene, butadiene, polypropylene		6,280
Cologne, Germany	Ethylene, propylene, butadiene, benzene, LDPE, LLDPE, ammonia, acrylonitrile and related products, EO and derivatives, PO and derivatives, other solvents and industrial chemicals		9,570
Geel, Belgium	Polypropylene		1,080
Grangemouth, United Kingdom	Ethylene, propylene, butadiene, benzene, ethanol, HDPE, LLDPE, polypropylene		5,600
Green Lake, Texas	Acrylonitrile and related products		1,330
Lavéra, France(3)	Ethylene, propylene, butadiene, benzene, PIB, HDPE, polypropylene, EO and derivatives, other solvents and industrial chemicals		3,950
Lillo, Belgium	Polypropylene, HDPE		1,350
Marl, Germany(4)	Styrene, polystyrene, EPS		1,290
Sarralbe, France	Polypropylene, HDPE		1,050
Texas City, Texas(5)	Styrene		1,070
Other facilities(6)			5,230
Total			40,360

(1)	Capacity is defined as nameplate capacity. See “— Manufacturing — Overview” for more information on how we calculate capacity. For facilities that we operate in a joint venture, the table shows only the portion of the facilities’ capacity attributable to our share in the joint venture.
(2)	On August 10, 2005, we experienced a fire at one of the crackers at our Chocolate Bayou facility, which will result in a loss of some of our olefins production volumes for 2005.
(3)	This facility consists of a combination of units fully owned by us and various 50/50 joint ventures between us and Total.
(4)	Capacity figures include 100% of the capacity of the facilities we agreed in May 2005 to contribute to our polystyrene and EPS joint venture with NOVA in May 2005. Excludes the facility’s cumene capacity, as the plant that we own and operate is used exclusively for supplying a third party under a toll manufacturing agreement.
(5)	Capacity figures do not include the propylene capacity of the facility’s propylene concentration unit which we plan to close by the end of 2005.
(6)	Capacity figures include the capacity of third-party facilities that provide us with products under various commercial agreements.

Refining

Introduction

      We own and operate two refineries, one in Grangemouth, United Kingdom, and one in Lavéra, France. Both refineries are fully integrated with our petrochemical plants located at the same sites. Grangemouth has direct access to crude oil from the North Sea, and Lavéra benefits from its ability to process a broad range of crude oil blends. Our principal refining products are transport fuels, naphtha, and heating and fuel oils. Most of the naphtha we manufacture is used as feedstock by the olefins crackers of our O&P Europe segment. We have entered into

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contracts with BP for the purchase of crude oil and the marketing of all of our refinery production except for the naphtha we use in our petrochemical business, until December 31, 2006 and beyond, with contract terms varying by product and customer segment. In addition, we have entered into agreements with BP under which they assist us with the disposal of bulk refinery products to ensure our continued access to the commodity markets. See “Certain Relationships and Related Transactions — Commercial Interface Agreements — Supply and Trading Agreements — Sale and Purchase Agreements” and “— Inland Refined Products Sale and Purchase Agreements” for a description of these agreements.

      The following table provides a breakdown of the revenues, adjusted EBITDA and total assets of our refining business for the periods and as of dates indicated:

							As of and for
	As of and for the year ended						the six months
	December 31,						ended June 30,
	2002		2003		2004		2004		2005
	($ in millions)
Revenues(1)		3,876		4,779		6,555		2,699		4,331
Adjusted EBITDA(2)		44		199		410		164		436
Total assets				1,354		1,609				2,604

(1)	Revenues exclude revenues from discontinued operations. See “Managements Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations” for more information on revenues from discontinued operations.
(2)	For more information on how we calculate adjusted EBITDA, see “Selected Combined Financial Data — Use of Non-GAAP Financial Measures.”

     The increase in the revenues of our Refining segment in 2003 and 2004 reflects the fact that oil prices increased significantly over the past several years. The rise in our adjusted EBITDA is consistent with higher refining cash margins across the industry, which were driven by continued strong demand for refinery products, modest capacity growth in the industry and growth in supply of cheaper, heavier and more sour crude oil relative to more expensive, lighter and sweeter crude oil.

Our Refineries

Overview

      Both of our refineries are strategically important to us as they benefit from extensive integration with the petrochemical plants located on the respective sites. This integration is beneficial because it allows us to maximize the value from hydrocarbon flows between refining and petrochemicals, as well as to leverage the sites’ infrastructure, energy management and work force and realize feedstock synergies in both directions.

      Both of our refineries are larger than the European average, as each has a distillation capacity of over 200 mbd. They are also unusual refineries by European standards in that both combine an HC with an FCC. The combination of these two units permits us to manufacture light, low sulfur middle distillates, principally diesel. Moreover, with the hydrocracking technology employed by them, both refineries are able to produce high quality diesel. This constitutes a competitive advantage as Europe is short of high quality diesel, a position that is not likely to change as the demand for middle distillates continues to grow. Middle distillates currently account for approximately 45% of the volumes manufactured by Grangemouth and approximately 50% of the volumes produced by Lavéra.

      Both of our refineries are able to produce clean fuels meeting current European Union specifications, which limit the sulfur content of these fuels to 50 ppm. Our clean fuels investments in the Grangemouth refinery have enabled it to manufacture clean fuels containing no more than 10 ppm of sulfur, which is expected to become the maximum allowable level in the European Union in 2009. This specification requires a lower sulfur content than the 500 ppm of sulfur (which will be reduced to 15 ppm beginning June 1, 2006) and the 30 ppm of sulfur currently permitted by the more restrictive diesel and gasoline specifications, respectively, in the United States. Lavéra is compliant with the current European Union specifications, and we are in the process of making further investments to achieve compliance with the 10 ppm sulfur specifications by the end of 2007.

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      As with our petrochemical facilities, we undertake turnarounds of our refineries to carry out necessary inspections and testing to comply with industry regulations. These outages also permit us to perform additional maintenance activities, as necessary. Where possible, we seek to schedule the timing of turnarounds to coincide with periods of relatively low demand for the products of the relevant refinery. Refineries typically undergo major turnarounds every four to five years, with each turnaround lasting several weeks.

      One of the challenges faced by our refining business is that both of our refineries have an ageing infrastructure which requires significant investments. We believe our investments in the infrastructure, utilities and logistics of our refineries historically have been below industry average. In recent years, we have increased our investments at Grangemouth, and we intend to continue to make appropriate investments in the future to improve our refineries’ reliability and to meet tightening regulatory requirements.

      As is the case with other refineries that are integrated with petrochemical facilities, both of our refineries are slightly below industry average in terms of their upgrading complexity. This is primarily because the naphtha produced by integrated refineries such as ours is used as feedstock for the adjacent petrochemical plants, whereas the naphtha manufactured by non-integrated refineries is typically upgraded into gasoline.

      Another consequence of their lower than average upgrading complexity is that our refineries have a higher than average fuel oil yield.

Grangemouth

      Our Grangemouth refinery has a maximum crude oil distillation capacity of 205 mbd. On the supply side, the refinery benefits from the fact that it is vertically integrated with its feedstock sources through a direct connection with the FPS, a pipeline that carries crude oil from a variety of oil fields in the North Sea. Known as the Forties blend, this light, sweet crude oil accounts for the majority of the refinery’s feedstock mix. We have entered into a two-year agreement with BP for the supply of Forties blend at market-related prices, after which we intend to have completed an $8 million investment in our infrastructure, which will allow us to purchase Forties blend from any of the oil companies using the FPS. The balance of the refinery’s feedstock consists of heavier, more sour crude oils from the North Sea, Russia and Africa. The composition of the refinery’s crude slate will change and become heavier and more sour with the entry of the Buzzard oil field into the Forties blend, which is currently expected to occur in 2006. Due to its technology and configuration, Grangemouth will be able to process this crude oil and will also have the ability to process other low-cost, high-acid crude oils, such as crude oils from Russia, and other crude oils available from non-traditional sources. The rising proportion of low-cost, high-acid crude oil in Grangemouth’s crude oil slate over in the past several years has improved the refinery’s cash margins.

      On the product side, Grangemouth is well-positioned due to the fact that it is the only refinery in Scotland and has convenient access to the markets in Scotland, Ireland and northern England. The refinery produces more gasoline than its local markets can consume. Accordingly, it exports gasoline components to other markets. The refinery can access the U.S. markets for gasoline and gasoline blending components by shipping from the west coast of Scotland via a pipeline which starts at the refinery, runs across Scotland and terminates at the deep-water Finnart terminal at Loch Long.

      Grangemouth has a cogeneration unit operated by a third party, which provides steam and electricity at a lower cost than traditional generation facilities. Cogeneration is a highly efficient process that enables us to have flexibility in the use of various by-product fuels from our refining and petrochemical units in the generation of steam and electricity.

      As discussed above under “— Petrochemicals — Manufacturing,” we experienced significant reliability problems at Grangemouth in 2000 and 2001. These problems, among other things, damaged the refinery’s FCC and culminated in a government inspection and the imposition of fines. We have made significant investments in our Grangemouth site to address these issues. In 2004, we brought the FCC back online. The reliability of our Grangemouth refinery improved from 88% in 2001 to 94% in 2002, 94% in 2003 and 96% in 2004. However, we experienced reliability issues at our Grangemouth refinery in the first six months of 2005, and as a result our reliability rate at Grangemouth during this period was 88%.

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Lavéra

      Our Lavéra refinery has a maximum crude oil distillation capacity of 207 mbd. On the supply side, the refinery benefits from its location and its high level of flexibility in processing a broad range of qualities of crude oil. Its ability to upgrade heavy, sour crude oil into light, low sulfur products, enables it to take advantage of the wide variety of crude oils available primarily through the Mediterranean markets. This is especially beneficial in light of the increasing availability of new crude oils from Russia and other countries of the former Soviet Union. According to Wood Mackenzie Limited (WM), in 2004, Lavéra ranked first for distillation capability in France.

      The reliability of the refinery at our Lavéra site improved from 91% in 2001 to 91% in 2002, 94% in 2003 and 96% in 2004.

      On the product side, Lavéra benefits from its ability to export both to continental Europe and other Mediterranean markets, including the Middle East and north Africa. In addition, Lavéra has a product slate rich in middle distillates, for which there is a shortage in the European market. The refinery also has the capability to manufacture asphalt, a liquid used in road surfacing and roofing, which can be sold to customers in profitable specialty markets in France, the Middle East, Africa and other regions. This capability gives us increased flexibility in our selection of crude oil and in the optimization of our operations at Lavéra. Furthermore, the bunker fuel market served by Lavéra is currently strong, and, unlike the market for domestic fuel oil, we do not expect it to become subject to further sulfur restrictions for the foreseeable future.

Products

      The following table shows the sales volumes of our refined products for the period indicated:

	For the
	year ended
	December 31,
	2004
	(Barrels in
	thousands)
LPG		8,030
Naphtha		19,620
Gasoline		31,830
Jet fuel/kerosene		15,710
Diesel		33,160
Gas oil/heating oil		15,420
Fuel oil		16,150
Asphalt		1,190

      In 2004, high-value transport fuels (gasoline, jet fuel and diesel) accounted for approximately 60% of our total volumes. We are well-positioned to serve the transport fuel market in the future, given that Grangemouth is able to manufacture clean fuels in accordance with the stringent clean fuels requirements currently applicable in certain parts of the United States and the even stricter requirements which are expected to become applicable in Europe in 2009 and that we are in the process of making investments in Lavéra to achieve compliance with the expected 2009 European requirements by the end of 2007.

      The naphtha output of our refineries is primarily used as inputs by the co-located petrochemical facilities. The balance of our refinery products is transferred to BP, which either markets them to its customers or trades them on the commodity markets on our behalf. All transfers from us to BP are made at prices which are based on market prices.

Raw Materials and Energy

      The primary feedstocks of our refineries are crude oil, condensates, atmospheric residues, hydrogen and a range of blend components such as pygas. Both of our refineries are able to process different qualities of crude oil. The main variables in the selection of a particular type of crude oil are price and quality. Heavy, high-sulfur, sour slates are cheaper than lighter, sweeter slates. However, because high-sulfur crude oils require more

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processing, refineries that purchase primarily lower cost crude oils incur higher fixed costs. Processing high-sulfur crude oil also requires greater energy expenditures.

      Our Grangemouth, United Kingdom, refinery has a light, sweet crude oil slate, reflecting the dominance of the Forties blend in its crude slate, which accounts for more than three quarters of its total feedstock requirements. The balance comprises heavier crude oils from the North Sea, Russia and Africa. The composition of the refinery’s crude slate will change and become heavier and more sour with the entry of the Buzzard oil field into the Forties blend, which is currently expected to occur in 2006. Our refinery in Lavéra, France has a heavier, more sour crude slate than Grangemouth, comprising various blends, principally from Russia and the countries of the former Soviet Union, the Middle East and North and West Africa.

      In Grangemouth, we obtain the crude oil sourced through the FPS from BP through a Master Feedstock Sale and Purchase Agreement for Crude Oil, with rates based on market prices. The agreement has a minimum duration of two years, and when it expires, we expect to either enter into another contract with BP or purchase Forties blend oil from other suppliers, as we currently do with the respect to the balance of our requirements. We believe we do not depend on BP as a supplier of crude oil or other feedstocks and would be able to replace the feedstocks obtained through the FPS by purchases on the spot market. See “Certain Relationships and Related Transactions — Commercial Interface Agreements — Supply and Trading Agreements — Sale and Purchase Agreements” for a description of these agreements.

      Energy cost is the single largest operating expense of a refinery. The main sources of energy for our refineries are gas and fuel derived from the crude oil feedstock, supplemented by methane, electricity and steam. Our refineries and associated petrochemical units are fully integrated and use a single steam and power generation infrastructure at each refinery, consisting of power stations, long-term contracts with local utility companies and, at Grangemouth, a cogeneration unit operated by a third party.

Transportation

      Grangemouth receives all of its crude oil requirements by ship and pipeline, while Lavéra receives all of its oil requirements by tanker ships. With the exception of the Finnart pipelines, which deliver crude oil to our Grangemouth refinery and refinery product to the deep-water Finnart terminal at Loch Long on the west coast of Scotland, we do not own any pipelines for crude oil or refinery products. All arrangements with third party pipeline operators are entered into by BP. Where we use third party shipping companies, BP negotiates the terms of contracts with the relevant third parties on our behalf, subject to our final approval before the execution of any contract. In addition, BP maintains the relationships with these third parties and provides shipping services, global assurance services and price information to us. The Grangemouth refinery serves its customers, the majority of which are located in the United Kingdom, by road, rail and ship and through a pipeline link to a nearby shipping terminal. The Lavéra refinery’s customers are located in a broader geographic region, and therefore most of the refinery’s off-take is shipped through pipelines.

Sales and Marketing

      We have made the strategic choice of focusing our refining business on bulk sales out of the refinery and not to set up a retail sales and marketing organization of our own. We have chosen to sell our refinery products to BP, which allows us to use BP’s extensive distribution capabilities for the onward transportation and sales of our refinery products to our customers. Accordingly, we do not currently need a sales and marketing organization of our own.

      Substantially all of the naphtha output of our refineries is used as inputs by the petrochemical plants located at the relevant sites. In addition, we have entered into an Inland Refined Products Sale and Purchase Agreement with BP for each of our Grangemouth and Lavéra refineries, pursuant to which BP has agreed to take off the balance of our refinery products and to either market these products to its local customers or trade them on the commodity markets on our behalf. All transfers under these agreements are made at market-related prices. Most of the term sheets under the agreements entered into with respect to our Grangemouth refinery have fixed terms ranging from three to seven years from January 1, 2005. Under the Grangemouth agreements, we are required to sell our refinery products exclusively to BP for so long as BP continues to hold more than 50% of the voting

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power of our capital stock. The term sheets under the agreements entered into with respect to our Lavéra refinery expire between 2008 and 2011 and generally may be terminated upon written notice with periods ranging from one to three years, depending upon the refinery product. All transfers under the agreements are made at market-related prices. Under the Lavéra agreements, we are required to sell all of our products to BP. However, there are exceptions for the supply of products to specified third parties for those third parties’ own use. See “Certain Relationships and Related Transactions — Commercial Interface Agreements — Inland Refined Products Sale and Purchase Agreements” for a description of these agreements.

Intellectual Property

      BP has agreed to grant us long-term access to any intellectual property owned by it that is required for our refining operations, such as refining process models used to optimize the performance of our units. We have also signed agreements with BP providing for the continuation of process support through the end of 2006. Process support includes assistance with the day-to-day operation of our refineries and also with projects and developments aimed at increasing our profitability through improvements in the various refining technologies. In addition, all existing licenses that have been granted to BP in order to operate specific process units have been or will be transferred to us. We are utilizing the transition period to review our support needs and are developing options for operational support.

Competition

      The refining industry is highly competitive. The main competitive factors are feedstock prices, refinery configuration and operating costs. According to WM, measured by capacity at December 31, 2004, we were the ninth largest refining company in Europe. Grangemouth is the only refinery in Scotland and one of eleven refineries in the United Kingdom. As Scotland’s infrastructure for distributing imported oil is limited, the refinery has a competitive advantage since competitors must either exchange product with us or import from abroad in order to access the Scottish market. Some competition results from the fact that several large refineries in north west Europe are able to supply the market via third party storage facilities. Lavéra is the largest refinery in its region, which comprises south-eastern France, Switzerland and south-western Germany. In its local market, it competes with four other refineries.

      We have entered into an Inland Refined Products Sale and Purchase Agreement for each of our refineries, pursuant to which BP has agreed to purchase all of our refining products, except for the petrochemical feedstock which we use internally. If either we or BP terminate one or both these agreements, we will need to establish a sales and trading function in order to sell our products through wholesale and retail outlets. In Scotland, the market is dominated by integrated companies with refining and retail marketing operations, which supply the Scottish market from the refineries in other countries or through exchange arrangements with BP, while in France independent marketers account for a larger portion of the retail market. While our location in Scotland would provide us with a strong basis for selling refinery products into the retail market once our agreements with BP expire, in France there is open access to the transportation infrastructure, which results in a very competitive market for suppliers. See “Certain Relationships and Related Transactions — Commercial Interface Agreements — Inland Refined Products Sale and Purchase Agreements” for more information on these arrangements.

Health, Safety, Security and the Environment

General

      Our operations involve the transportation, manufacturing, storage, handling and processing of large volumes of hazardous materials, including toxic and flammable compounds. As a result, HSSE risks are inherent in our business. In the ordinary course of our business, we are subject to environmental inspections, monitoring and occasional investigations by governmental authorities, which in some cases have resulted in, and may in the future result in, fines or penalties or other expenditures. In addition, our production facilities require us to hold multiple operating permits that are subject to renewal, modification and, in certain circumstances, revocation. Any actual or alleged violations of HSSE laws, regulations or permit requirements or failure to obtain any

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required permits could result in restrictions or prohibitions on our operations, civil or criminal sanctions, as well as, under some HSSE laws, strict liability and/or joint and several liability. Changes in HSSE regulations have the potential to inhibit or interrupt our operations, or require us to modify our facilities or operations. HSSE regulatory matters may cause us to incur significant unanticipated losses, costs or liabilities.

HSSE Management Systems

      The health, personal safety and security of our employees, customers and the communities in which we operate are vital to our success, as are the security and integrity of the places in which our employees work and the equipment and other assets they use. We have a set of HSSE policies and procedures in place at all of our facilities that build upon those BP HSSE systems that were already in place at many of our facilities. As a separate company, our HSSE management systems will assist us in achieving our HSSE compliance goals while also improving our operational efficiency and minimizing our overall risks of doing business. An important aspect of our HSSE management strategy will be to manage HSSE compliance requirements on a site-specific basis, taking into account the various operational and HSSE-related risks associated with a particular site.

HSSE Related Liabilities

Environmental Remediation and Closure Liabilities

      Environmental laws and regulations may require us to remediate or otherwise redress the effects on the environment of prior disposal or the release of hazardous substances by us or, in some cases, other parties. We presently have remediation and closure obligations at certain sites, including refineries, petrochemical plants and waste disposal sites and will likely incur obligations at other sites in the future.

      BP has agreed to indemnify us, subject to certain limitations, for certain liabilities, including any claims and losses we may incur with respect to:

•  any liabilities related to off-site waste disposal prior to April 1, 2005 (excluding liabilities related to certain waste disposal sites located near our facilities in Cologne, Germany, and Sarralbe, France,); and

•  any liabilities related to former facilities which, as of April 1, 2005, had been sold, closed or decommissioned.

      We will retain all other environmental remediation or closure obligations, whether known or unknown, relating to the businesses and assets being transferred from BP to us, including any interests in pipelines or jetties, irrespective of whether they occurred before April 1, 2005 or thereafter. We will also retain liability for off-site waste disposal from our facilities that occur on or after April 1, 2005.

HSSE Accruals

      At December 31, 2004, we had recorded approximately $17 million in financial accruals relating to anticipated environmental related obligations, including offsite waste liabilities and contaminated land liabilities at certain sites. In addition, we had established approximately $19 million in financial accruals for decommissioning and demolition obligations at certain sites. Under GAAP, accruals are established when potential liabilities are either known or considered probable and have been reasonably estimated. These estimates do not include accruals established relating to liabilities retained by BP. In addition, there exist other potential remediation risks at some of our sites where financial accruals have not been provided, because these potential liabilities are either not probable or are considered probable but are not currently estimable.

      Furthermore, we may in the future be required to establish additional financial accruals for environmental liabilities associated with onsite waste disposal activities, off-site waste disposal activities from our sites occurring after April 1, 2005, obligations relating to any future site closures, process equipment at our facilities that is already idle or for which demolition or decommissioning estimates have been made, and potential liabilities associated with contaminated land and groundwater at our sites.

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Health and Safety Liabilities

      We also may incur costs for health and safety liabilities associated with our products. Potential liabilities could also exist from employee or contractor exposure to hazardous materials. We currently are not aware of any facts that would require us to make provisions for any such potential liabilities, although we may need to establish financial accruals for them in the future as more information becomes available.

      Under the terms of our separation from BP, BP has agreed to indemnify us, subject to certain limitations, for:

•  any claims for exposure to hazardous materials at our facilities to the extent that such claims were either made prior to April 1, 2005 or threatened in writing prior to April 1, 2005 and made prior to April 1, 2006 or, in certain cases, to the extent that such exposure related to events that occurred prior to April 1, 2005; and

•  certain product liability claims related to products manufactured prior to April 1, 2005.

      We have agreed to assume all other health and safety related liabilities related to the assets transferred to us in connection with the separation.

HSSE Related Capital Expenditures

      We incurred $96 million, $151 million, $172 million and $54 million in HSSE-related capital expenditures for 2002, 2003, and 2004 and for the six months ended June 30, 2005, respectively. We expect to incur an estimated $140 million of such expenditures for the remainder of 2005. Although we cannot predict with certainty future capital expenditures, from 2005 to 2010 we expect to incur an estimated total of $830 million in HSSE-related capital expenditures, which includes $660 million in capital expenditures to comply with various regulations related to health, safety, security and the environment and an additional $170 million to meet industry good practice and internal safety standards. An estimated $490 million of this estimated total is expected to be made specifically to comply with various environmental regulations, which include an estimated $350 million related to compliance with the EU directive on IPPC. We anticipate that HSSE regulations will continue to require us and the industry in general to make capital expenditures. Since capital expenditures vary with applicable HSSE legal requirements, we cannot assure you that our recent capital expenditures are indicative of the amounts we may be required to spend to comply with future HSSE legal requirements.

Environmental Regulatory Matters and Developments

North America

United States Clean Air Act

      In the United States, the Clean Air Act requires, among other things, sulfur reductions; enhanced monitoring of major sources of specified pollutants; stringent air emission limits and new operating permits for chemical plants. This law affects our facilities in the United States producing, manufacturing and distributing petrochemical products. Federal and state controls on ozone, carbon monoxide, benzene, sulfur, and nitrogen dioxide impact our activities and products in the United States.

      Title V of the Clean Air Act imposes federal requirements which dictate that all of our facilities in the United States obtain operating permits. Our facilities either currently have operating permits or have submitted Title V permit applications and are awaiting approval from the appropriate regulatory agencies. Affected facilities with Title V permits are required to make regular reports, certify compliance with operating permit conditions and report all deviations from any operating permit conditions. Some of our facilities which have submitted these reports have reported a number of deviations to the conditions of their Title V permits, though we believe these deviations to not be material at this time.

      By 2007, our facilities in south Houston, Texas, and Lima, Ohio must comply with new nitrogen oxide emission standards under the Clean Air Act. These new standards are being phased in through 2007. While we may purchase emissions allowances to partially meet these new nitrogen oxide emission standards, modifications to existing equipment and the installation of additional control equipment are required. Clean Air Act regulations

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have also been issued concerning emissions of highly-reactive volatile organic compounds (such as ethylene and propylene). We expect that additional estimated capital expenditures of $40 million will be required to comply with the Clean Air Act standards and regulations.

      In April 2005, the United States Environmental Protection Agency (EPA) inspected our Lima, Ohio facility as part of a broader investigation by the EPA of the chemical industry’s compliance with certain emission standards relating to hazardous organic pollutants. We have not yet received the results of the inspection or received any notices of violations, but if an enforcement action is brought by the EPA, it is reasonable to believe that we may be subject to fines or penalties in excess of $100,000 or be required to undertake other actions.

European Union

Directive for Integrated Pollution Prevention and Control

      The IPPC is the most significant environmental regulation affecting our operations in Europe over the next three years. The IPPC attempts to minimize pollution from various point sources throughout the European Union through a single permitting process and requires facilities covered by the Directive to obtain an IPPC operating permit from the authorities in the relevant EU member states. The permits must be based on the concept of Best Available Technology (BAT), which in some cases involve environmental control improvements to prevent, minimize and control pollution from a facility. If the use of BAT is likely to result in the breach of an environmental quality standard under IPPC, plant emissions must be reduced accordingly.

      All plants in Europe affected by IPPC must obtain an IPPC operating permit by November 2007 or have an agreed improvement program in place. The Directive encompasses most activities and processes undertaken by the oil and petrochemical industry within the EU. All of our affected facilities in the EU have applied for their IPPC permits as required by local EU member state legislation, but as the implementation deadline approaches, there may be amendments to our permits and, in some cases, a requirement to apply for new permits. We expect to incur increased costs in maintaining compliance with IPPC and we expect to incur estimated capital expenditures of $350 million to comply with these standards at our facilities in Europe through 2010.

Large Combustion Plant Directive

      Our European operations are also subject to the EU Large Combustion Plant Directive, which aims to reduce acidification, ground level ozone and particles throughout Europe by controlling emission limit values for sulfur dioxide, nitrogen oxides and particulates from combustion plants with a thermal output of greater than 50 megawatts. The initial Directive required phased-in reductions in emissions from existing large combustion plants on or before April 1, 2001. A revised Large Combustion Plant Directive has been agreed and implementation plans by the EU member states for the revised Directive were required to be submitted to the EU by November 27, 2003 and large combustion plants must be in full compliance with the Directive by January 1, 2008. Our expected capital expenditures for complying with IPPC will also assist in us in complying with the Large Combustion Plant Directive, but we will still need to incur additional estimated capital expenditures of $40 million through 2010 to comply with such regulations at several of our facilities in Europe.

European Union Emissions Trading Scheme

      Some of our operations in Europe are also subject to the European Union Emissions Trading Scheme (EU ETS). By setting an overall cap on carbon dioxide emissions, the EU ETS authorizes emissions allowances to be issued to specified EU large stationary installations and allows for the trading of such allowances across the EU. Each installation achieves compliance by surrendering enough allowances to cover its emissions in each annual period. Emissions are treated as a liability and emission allowances are treated as an intangible asset. Allocations of carbon dioxide emissions allowances to each of our affected facilities have been made under each EU member state’s National Allocation Plan. The National Allocation Plans have been approved by the European Commission and allowances have now been issued for each of our installations. However, since our emissions can vary, we may be required to purchase additional allowances at the prevailing market price which may increase our operating costs.

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Health and Safety Regulatory Matters and Developments

Product Stewardship

      While most of our products have some hazardous properties, some of them, such as acrylonitrile, require specialized handling procedures due to their acute and chronic toxicity. Furthermore, our polymer products have widespread end-uses in a variety of tightly regulated consumer industries, including in food packaging and medical applications. To manage these risks, our product stewardship team works closely with industry associations, government regulators and other stakeholders to strive for positive solutions in setting regulations which are based in science and are commensurate with the magnitude of the risk. The various aspects of our business are also careful to ensure that transporters and customers have the appropriate information and processes to properly manage our products.

Registration, Evaluation, and Authorization of Chemicals (REACH)

      The European Union is currently proposing to introduce new legislation requiring much greater control of the use of chemical products within the European Union by giving the affected industries the responsibility for ensuring and demonstrating the safe manufacture, use and disposal of chemicals. In 2003, the European Commission adopted an official proposal for a future regulation on European chemical policy referred to as Registration, Evaluation and Authorization of Chemicals (REACH). This proposal is being discussed by the European Parliament and the Council of the European Union. Depending on the outcome of these discussions, the regulation could enter into force by 2007 and could require additional testing, documentation and risk assessments for products manufactured by the chemical industry. We are currently part of a collaborative industry approach to comply with these regulations, which will affect both our petrochemicals and refinery products. The ultimate cost of REACH may vary depending on the final requirements of the regulation and at this time it is uncertain what the estimated costs of complying with the final regulations may be, although such costs could be substantial. The costs of registering and authorizing certain products and the restrictions placed upon them may affect the demand for those products from our customers.

Major Accident Risk

      The safety of our sites is a top priority because system failures or accidents can present a health and safety risk to our employees and people who live or work near our facilities.

      Within the European Union, the EU directive on the control of major-accident hazards (Seveso II Directive) regulates facilities that present a risk of accidents involving hazardous materials and impose specific plans and procedures, particularly for the storage of such materials. The directive contains general and specific obligations on both operators and the member states’ authorities. The provisions provide for control measures aimed at the prevention of major accidents and the limitation of consequences of major accidents. All operators of establishments coming under the scope of the Directive must provide a safety plan to the competent authority and establish a major-accident prevention policy. In addition, facilities holding even larger quantities of dangerous substances above the upper threshold contained in the Directive (upper tier establishments) must establish a safety reporting system, a safety management system and an emergency plan. We have ten facilities in Europe which are considered upper tier establishments under the Directive.

      Within the United States, our facilities are subject to the Occupational Safety and Health Administration Process Safety Management (PSM) standard, implemented in 1992, which requires management of major accident risk with fourteen elements of management controls. Included in the mandatory management controls are requirements for operator training, mechanical integrity, incident investigation, and process hazard analysis. All facilities subject to the PSM standard undergo PSM compliance audits every three years.

Security and Crisis Management

      The Department of Homeland Security Act, Marine Transportation Security Act (MTSA) and Department of Transportation Hazardous Material security compliance regulations require many of our sites and facilities in the United States to conduct security vulnerability assessments, which include the preparation of security mitigation

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plans, implementation of upgrades to security measures, appointment and training of a designated security person and submission of plans for approval and inspection. Additionally, proposed EU legislation would require similar standards at our petrochemical facilities in Europe. Our United States facilities, in partnership with American Chemical Council, meet the requirements of the Responsible Care Security Code, a facility security plan to protect our chemical facilities, our communities and our products. All of our facilities worldwide have a multi-tiered response system for emergency response and crisis management. Facilities in other regions are periodically assessed to ensure that they meet appropriate security standards and safeguards.

Employees

      We have a diverse and highly skilled workforce with a high degree of commitment to our business and our strategic and operational goals. A significant percentage of our employees are covered by collective bargaining agreements that determine such matters as compensation, working hours and other conditions of employment, and are represented by works councils. During the last three years, we have not experienced any material labor disputes resulting in work stoppages. We believe that our relationship with our employees is good, and we have taken steps to ensure the continued support of our employees while we transition to a separate, standalone company. To that end, we have committed to our employees that we would maintain equivalent employment terms and conditions to those offered by BP for a period of at least one year after completion of the offering. While this decision has allowed us to continue our good relations with our employees, we cannot assure you how our employees would respond if we were to make any changes after the one-year period has expired.

      We have approximately 8,000 employees. This figure includes employees who became employed by our company as a result of our acquisitions of Solvay’s interests in our former HDPE joint ventures with that company. The figure excludes the approximately 180 employees who will move to our joint venture with NOVA, as well as the employees at BP’s facility in Wingles, France, which may be transferred to the joint venture in 2007 if put or call options provided for in the agreements relating to the formation of the joint venture are then exercised. The figure also excludes employees of the various joint ventures at our site in Lavéra, France. In addition, the figure excludes the approximately 270 individuals seconded to us by BP, some of whom will be retained by us and become employees of our company, and some of whom will be redeployed to BP or be made redundant. Finally, the figure excludes BP employees who work at our Carson, California, Texas City, Texas, and Whiting, Indiana, facilities, which for labor law reasons have not been transferred to us as part of our separation from BP, as well as employees at the LAO facility in Pasadena, Texas, which is owned by BP and operated for us on a toll manufacturing basis.

      In addition, we employ a significant number of contractors at our sites. Our contractors are mostly engaged in turnarounds, maintenance and construction work.

Legal Proceedings

      As is the case with many companies in the petrochemical industry, we are and may from time to time become a party to claims and lawsuits incidental to the ordinary course of our business. We are not currently involved in any legal or arbitration proceedings that we expect to have a material adverse effect on our financial position, and, to our knowledge, no such legal or arbitration proceedings are currently threatened.

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MANAGEMENT

Directors and Executive Officers

      Set forth below are the names, ages, as of July 1, 2005, and current positions of our present directors and executive officers:

Name	Age		Position
Ralph Alexander		50	President, Chief Executive Officer and Director
Ross Pillari		55	Chairman of the Board and Director
Stephen Elbert		58	Director
Stephen Riney		44	Director
Stephen Winters		55	Director
Mark Tomkins		50	Chief Financial Officer
Henry Kleeman		47	Senior Vice President, General Counsel and Secretary
Didier Baudrand		50	Senior Vice President, European Operations
Dennis Seith		49	Senior Vice President, North American Operations
K’Lynne Johnson		37	Senior Vice President, Global Derivatives
Peter Cella		47	Senior Vice President, Business Support and External Affairs
Paul Adams		46	Senior Vice President, Business Optimization and Procurement
Jay Kouba		52	Senior Vice President, Strategy
Stephen Davies		50	Senior Vice President, Human Resources, HSSE & Internal Communications
Jim White		49	Senior Vice President, Portfolio
Tom Muething		49	Controller

      Set forth below is a brief description of the business experience of the persons who serve as our directors and executive officers.

      Ralph Alexander — President, Chief Executive Officer and Director. Mr. Alexander has been our Chief Executive Officer since our formation as a separate legal entity within the BP Group in 2005. Prior to this appointment, Mr. Alexander held a variety of roles within BP. From January 2005 to June 2005, Mr. Alexander was the Chief Executive Officer of BP’s olefins and derivatives business. From July 2004 to December 2004, Mr. Alexander was the Chief Executive Officer of BP’s Petrochemicals business, and from April 2002 to June 2004, he was the Executive Vice President and Chief Executive Officer of BP’s Gas, Power and Renewables segment. From September 2001 to March 2002, Mr. Alexander served as a Group Vice President in BP’s Exploration and Production segment. In this position, he held responsibilities for various regions of the world, including Russia, the Caspian, Africa and Middle East. Additionally, he was responsible for the segment’s recruitment, diversity and marketing activities. From September 1999 to August 2001, Mr. Alexander was Group Vice President with responsibility for global onshore oil activities as well as emerging gas activities in the Asia-Pacific region. Mr. Alexander has also held senior roles in BP’s Refining and Marketing segment. In addition, Mr. Alexander held senior roles in strategy development, mergers and acquisitions and performance management for the BP Group. Mr. Alexander holds a bachelor’s degree and master’s degree in nuclear engineering from New York Polytechnic University and a master’s degree in management science from Stanford University Business School. He is currently vice chairman of the Board of Trustees of New York Polytechnic University, a member of Stanford University’s Sloan Advisory Board, the Liquid Engine Advisory Board and the Society of Petroleum Engineers. In addition he serves as a nonexecutive director on the Board of Directors of Anglo American plc.

      Ross Pillari — Chairman of the Board of Directors. Mr. Pillari is a Group Vice President for BP and, since 2001, has been President and Chief Executive Officer of BP America Inc. Prior to this appointment, Mr. Pillari

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was BP’s Group Vice President for Downstream Marketing and was responsible for BP’s global marketing operations. Mr. Pillari is a member of the Board of Directors of The American Petroleum Institute, The Chicago Symphony Orchestra, The Foreign Policy Association, The Baker Institute Energy Forum, and The Alliance to Save Energy. Mr. Pillari is a graduate of Case Western Reserve University and the Stanford Executive Program.

      Stephen Elbert — Director. Mr. Elbert is Senior Vice President for remediation management of BP America Inc. and is responsible for managing BP’s environmental liabilities worldwide. Mr. Elbert also serves as Chairman and CEO of Atlantic Richfield Company, an affiliate of BP. Before his current position, Mr. Elbert was Vice President of Health, Safety and Environment (HSE) for BP’s Petrochemicals segment, with responsibility for HSE policies and performance. Mr. Elbert holds a Ph.D., master’s and bachelor’s degrees in biological science from the University of Louisville, DePauw University and The Ohio State University, respectively. He is a graduate of the Northwestern University’s Executive Management Program and the Advanced Management Program of the Harvard Graduate School of Business Administration.

      Stephen Riney — Director. Mr. Riney was appointed Vice President of Finance in the Americas for BP in March 2005. From January 2004 to March 2005, Mr. Riney served as the performance unit leader for BP’s Marlin and Horn Mountain production facilities in the Deepwater Gulf of Mexico. From February 2001 to January 2004, Mr. Riney was Vice President of Planning for BP’s global exploration and production business. Mr. Riney holds a bachelor’s degree in accounting from the University of Notre Dame and a master’s degree in business administration from the University of Chicago.

      Stephen Winters — Director. Mr. Winters is Associate General Counsel for BP’s Refining and Marketing segment and is responsible for BP’s corporate and specialty legal practice groups in the United States. Mr. Winters is a member of the Kansas, Illinois and U.S. Supreme Court bars, the American Bar Association and the American Corporate Counsel Association. He obtained his bachelor’s degree in English and psychology and a law degree from Kansas University.

      Mark Tomkins — Chief Financial Officer. Mr. Tomkins joined our company in May 2005 as Chief Financial Officer. Previously he was Senior Vice President, Chief Financial Officer and Treasurer of Vulcan Materials Company, a provider of construction materials and chemicals, a position he held since January 2001. Prior to that, Mr. Tomkins held the same position at Great Lakes Chemicals Chemical Corporation, which is now a part of Chemtura Corporation, and worked as Vice President, Finance and Business Development, for two chemical divisions of Allied Signal, Inc. Mr. Tomkins is a certified public accountant and holds a bachelor’s degree in business and a master’s degree in business administration from Eastern Illinois University.

      R. Henry Kleeman — Senior Vice President, General Counsel and Secretary. Mr. Kleeman joined our company as Senior Vice President and General Counsel in June 2005. Previously he was Vice President, Deputy General Counsel and Business Practices Officer at Sara Lee Corporation (Sara Lee) from 1999 to 2005. He was also the assistant secretary for Sara Lee and secretary to the audit committee of its Board of Directors. Mr. Kleeman holds a bachelor’s degree in English and economics from Colgate University and a law degree from the University of Chicago Law School. From June 2000 until June 2005, Mr. Kleeman was a director of Delta Galil Industries, Inc., a publicly traded apparel manufacturer.

      Didier Baudrand — Senior Vice President, European operations. Mr. Baudrand is the head of our O&P Europe segment. Mr. Baudrand held a variety of roles within BP over the past 26 years, including in the areas of lubricants, sales, marketing, logistics and chemicals. From July 2004 to June 2005, Mr. Baudrand served as Senior Vice President, European operations, for BP’s olefins and derivatives business. From January 2004 to July 2004, Mr. Baudrand was the Chief Executive Officer of our former joint venture with Solvay in Europe. From January 2002 to December 2003, Mr. Baudrand was the business unit leader of BP’s global polymers business and from January 2001 to December 2001 he was the business unit leader of BP’s European polypropylene business. Prior to this period, he served as Chief Executive Officer for BP’s European polypropylene business. Mr. Baudrand holds a master’s degree in physical chemistry from Paris University and a chemical engineering degree from the Ecole Nationale Superieure de Chimie de Paris. Mr. Didier Baudrand is a board member of the CEFIC organization and Vice President of Plastic Europe.

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      Dennis Seith — Senior Vice President, North American operations. Mr. Seith is the head of our O&P North America segment. Mr. Seith has 26 years of experience within BP’s Petrochemicals and Refining and Marketing segments, including in the areas of manufacturing, business management, project development, and management sales and planning. From July 2004 to June 2005, Mr. Seith was Senior Vice President, North American operations, for BP’s olefins and derivatives business. From January 2004 to June 2004, Mr. Seith was the business unit leader of BP’s refinery in Whiting, Indiana. From January 1999 to December 2003, he was the business unit leader of BP’s olefins business in North America with additional duties for the North American styrene business added in 2002. Mr. Seith holds a bachelor’s degree in chemical engineering from Texas A&M University.

      K’Lynne Johnson — Senior Vice President, Global Derivatives. Ms. Johnson is the head of our Global Derivatives segment. From May 2005, to June 2005, Ms. Johnson was Senior Vice President, Global Derivatives, for BP’s olefins and derivatives business. From January 2004 to April 2005, Ms. Johnson led BP’s global nitriles business as performance unit leader and Vice President, Business Optimization. From September 2002 to December 2003, Ms. Johnson was responsible for the global development of BP’s petrochemical e-commerce business, back office and demand supply planning automation. From February 2001 to September 2002, Ms. Johnson served as a director for demand supply planning. From January 1999 to February 2001, Ms. Johnson worked as a human resources manager for BP’s global specialty intermediates chemical business and the petrochemical technology function. Ms. Johnson holds a bachelor’s degree in psychology from Brigham Young University and a master’s degree in organizational behavior from the Marriot School of Management at Brigham Young University.

      Peter Cella — Senior Vice President, Business Support and External Affairs. Mr. Cella is responsible for planning and performance management, information technology, property management and services, and external affairs. From July 2004 to June 2005, Mr. Cella served as Senior Vice President, Business Support and External Affairs, for BP’s olefins and derivatives business. From May 2002 to June 2004, Mr. Cella served as the business unit leader of BP’s global olefins specialties and derivatives business. Between June 1999 and May 2002, Mr. Cella was the business unit leader of BP’s global fabrics and fibers business. Mr. Cella holds a bachelor’s degree in finance from the University of Illinois and a master’s degree in business administration from Northwestern University’s Kellogg Graduate School of Management.

      Paul Adams — Senior Vice President, Business Optimization and Procurement. Mr. Adams is responsible for trading, procurement and business optimization. Mr. Adams has 24 years of experience within BP. From July 2004 to June 2005, Mr. Adams served as Senior Vice President, Business Optimization and Procurement, for BP’s olefins and derivatives business. In 2003 and 2004, Mr. Adams served as special advisor to BP’s Group Vice President, Supply and Trading. Between 1998 and 2003, he was the head of BP’s U.S. oil trading and supply operations. Mr. Adams holds a bachelor’s of science degree from the London School of Economics and Political Science.

      Jay Kouba — Senior Vice President, Strategy. Mr. Kouba is responsible for developing our long-term business strategy, marketing, technology and licensing. Mr. Kouba has 24 years of experience with BP’s Petrochemicals segment. From July 2004 to June 2005, Mr. Kouba served as Senior Vice President, Strategy, for BP’s olefins and derivatives business and, earlier in 2004, as Vice President of Marketing, Sales and Logistics for BP’s Petrochemicals segment. Between 1999 and 2003, Mr. Kouba was Vice President, Technology, for BP’s Petrochemicals segment. Mr. Kouba holds a bachelor’s degree in chemistry from Stanford University, a master’s degree and doctorate in chemistry from Harvard University and a master’s degree in business administration from the University of Chicago.

      Stephen Davies — Senior Vice President, Human Resources, HSSE & Internal Communications. Mr. Davies is responsible for human resources, HSSE and internal communications. From July 2004 to June 2005, Mr. Davies served as Senior Vice President, Human Resources, HSSE and Communications, for BP’s olefins and derivatives business. From January 2003 to June 2004, Mr. Davies was Vice President of Global People (HR) Operations of BP’s human resources global operations department. From January 1999 to December 2002, Mr. Davies was Vice President, Downstream Human Resources, of BP’s downstream human resources department. Mr. Davies holds a bachelor’s degree from the University of Manchester. As a result of the design of

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certain BP pension arrangements, Mr. Davies is employed by BP and has been seconded to us. The secondment arrangement will expire in 2006.

      Jim White — Senior Vice President, Portfolio. Mr. White is responsible for developing and managing our portfolio options, transactions and opportunities. Mr. White’s 25-year career with BP spanned research, refining & marketing, marine fuels and lubricants, corporate head of BP’s Indonesian operations and, since 1996, petrochemicals. From July 2004 to March 2005, Mr. White served as Senior Vice President, Portfolio for BP’s olefins and derivatives business. From January 2004 to June 2004, he was Director, Portfolio Management, for BP’s petrochemical business. From January 2000 to December 2003, he was the business unit leader for BP’s global olefins and polymers development, where he led mergers and acquisitions activity, joint venture relationships, licensing and polymers technology. Mr. White holds a Ph.D and a bachelor’s of science degree in chemistry from City University, London. As a result of the design of certain BP pension arrangements, Mr. White is employed by BP and has been seconded to us. The secondment arrangement will expire in 2006.

      Tom Muething — Controller. Mr. Muething is our financial controller. Prior to his current role, Mr. Muething served as the Controller for BP’s olefins and derivatives business within BP’s Petrochemical’s segment from July 2004 to June 2005. From June 2003 to June 2004, Mr. Muething served as Segment Controller for BP’s Gas, Power and Renewables segment. From September 2000 to June 2003, Mr. Muething was a business unit leader within BP’s Gas, Power and Renewables segment accountable for marketing and business development activities in North America. Prior to September 2000, Mr. Muething was responsible for BP’s North American accounting services organization. Mr. Muething holds a bachelor’s degree in accounting from Xavier University and is a certified public accountant.

Board Practices

Board Structure

      Immediately upon completion of the offering, our Board of Directors will consist of up to nine directors, including   , who are independent directors. Our Board of Directors will be divided into three classes serving staggered three-year terms.

      At each annual meeting of our stockholders, directors will be elected to succeed the class of directors whose terms have expired. Class I directors’ terms will expire at the first annual meeting of our stockholders following the completion of the offering. Class II directors’ terms will expire at the second annual meeting of our stockholders following the completion of the offering. Class III directors’ terms will expire at the third annual meeting of our stockholders following the completion of the offering. Our classified board structure could have the effect of increasing the length of time necessary to change the composition of a majority of our Board of Directors. In general, at least two annual general meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of our Board of Directors.

      For so long as BP owns at least 50% of the voting power of the outstanding shares of our capital stock entitled to vote, we intend to avail ourselves of the “controlled company” exemption under the NYSE rules from the requirements that a listed company has a majority of independent directors on its Board of Directors and that its compensation and nominating and governance committees be composed entirely of independent directors.

Board Committees

      Our Board of Directors has an audit committee, a compensation committee, and a nominating and governance committee.

Audit committee

      Immediately upon completion of the offering, our audit committee will consist of no fewer than three members, each of whom our Board of Directors will have determined has no material relationship with us and is otherwise independent under the rules and regulations of the NYSE and the SEC. Our Board of Directors will also have determined that each member of the audit committee is financially literate and that the chairman of the audit committee, is an “audit committee financial expert” as defined under the rules of the SEC.

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      Our audit committee has general responsibility for the oversight of our accounting, reporting and financial control practices. Among other functions, the committee is responsible for (1) the appointment, compensation, retention and oversight of the work of our independent auditor; (2) assisting our Board of Directors in monitoring the integrity of our financial statements, our independent auditor’s qualifications and independence, the performance of our independent auditor and our internal audit function, and our compliance with legal and regulatory requirements; (3) reviewing with the chief executive officer and chief financial officer the design and operation of internal controls over financial reporting; (4) annually reviewing our independent auditor’s report describing the audit firm’s internal quality-control procedures and any material issues raised by the most recent internal quality-control review, or peer review, of the audit firm; (5) discussing the annual audited financial and quarterly financial statements with management and our independent auditor; (6) discussing earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies; (7) discussing policies with respect to risk assessment and risk management; (8) meeting separately and periodically, with management, internal auditors and our independent auditor; (9) reviewing with our independent auditor any audit problems or difficulties and managements’ response; (10) setting hiring policies for employees or former employees of our independent auditor; (11) annually reviewing the adequacy of the audit committee’s written charter and evaluating the performance of the audit committee; (12) handling such other matters that are specifically delegated to the audit committee by our Board of Directors from time to time; (13) establishing procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters; (14) reporting regularly to the full Board of Directors and (15) preparing an audit committee report for inclusion in the company’s annual proxy statement.

      In addition, for so long as BP remains our affiliate, the committee has the authority to review and approve any material contract, amendment to a material contract or other intercompany transaction between us and BP or any subsidiary or affiliate of BP (other than us and our subsidiaries) and to decide on the initiation and escalation of disputes between us and BP.

Compensation committee

      Immediately upon completion of the offering, our compensation committee will consist of up to three members, one of whom will be designated by BP and up to two of whom the Board of Directors will have determined have no material relationship with us and will otherwise be independent under the rules and regulations of the NYSE and the SEC. None of our executive officers serves on the compensation committee or Board of Directors of any other company of which any of the members of the compensation committee or the Board of Directors is an executive officer.

      Our compensation committee is responsible for (1) reviewing key employee compensation policies, plans and programs; (2) reviewing and approving the compensation of our chief executive officer and other executive officers; (3) reviewing and approving employment contracts and other similar arrangements between us and our executive officers; (4) overseeing compliance with any applicable compensation reporting requirements of the SEC; (5) retaining consultants to advise the committee on executive compensation practices and policies and (6) handling such other matters that are specifically delegated to the compensation committee by the Board of Directors from time to time.

Nominating and governance committee

      Immediately upon completion of the offering, our nominating and governance committee will consist of five members, one of whom will be an executive officer of our company, three of whom will be designated by BP and one of whom the Board of Directors will have determined has no material relationship with us and is otherwise independent under the rules and regulations of the NYSE and the SEC.

      Our nominating and governance committee is responsible for making recommendations to our Board of Directors regarding candidates for directorships and the size and composition of the board, overseeing our corporate governance guidelines and reporting and making recommendations to the board of directors concerning corporate governance matters.

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BP Common Stock Ownership of Directors and Executive Officers

      All of our common stock is currently owned by BP. Accordingly, none of our directors and executive officers currently owns any shares of our common stock. However, upon consummation of the offering, those of our executive officers who currently hold unvested performance units under BP’s Long-Term Performance Plan (LTPP) will receive restricted stock units with respect to our common stock under the Conversion Plan. In addition, upon consummation of the offering, our executive officers will receive stock options and restricted shares under the Incentive Plan and will be entitled to purchase shares and receive stock options under the Executive Share Matching Plan. See “— Innovene “BP LTPP” Conversion Plan”, “— Innovene Incentive Plan 2005” and “— Innovene Executive Share Matching Plan” for more information on each of these plans.

      The following table sets forth, as of August 1, 2005 the number of shares of BP common stock and options to purchase BP common stock held by our directors, those of our executive officers named in the Summary Compensation Table below under “— Executive Compensation” and all of our directors and executive officers as a group. Except as otherwise noted, each of the directors and executive officers named in the table below (including their respective family members) had sole voting and investment power with respect to the BP common stock.

	BP common stock and
	securities underlying
	options beneficially
Name	owned(1)(2)(3)
Ralph Alexander		580,612
Ross Pillari		515,152
Stephen Elbert		187,836
Stephen Riney		83,730
Stephen Winters		405,303
Didier Baudrand		129,597
Dennis Seith		120,240
All directors and executive officers as a group (17 persons)		*(4	)

(1)	Beneficial ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities. Shares of BP common stock subject to options that are exercisable or will become exercisable within 60 days of June 30, 2005 are deemed to be outstanding and to be beneficially owned by the person holding the options.
(2)	ADSs held by the relevant director or executive officer have been converted into shares at a ratio of one ADS for every six shares of BP common stock.
(3)	Includes (a) awards of restricted shares of BP common stock, ADSs and stock units under the BP LTPP which have not been deferred by the relevant executive officer or director, (b) shares of BP common stock and ADSs currently held in a BP retirement plan and (c) shares of BP common stock and ADSs underlying options that are currently exercisable or will become exercisable within sixty days of June 30, 2005 for each of the following executive officers or directors: Ralph Alexander (528,444); Stephen Elbert (157,224); Stephen Riney (79,800); Stephen Winters (385,974); Didier Baudrand (53,200); and Dennis Seith (68,940). ADSs underlying options have been converted into shares at a ratio of one ADS for every six shares of BP common stock.
(4)	The shares of BP common stock and securities underlying options beneficially owned by all directors and executive officers as a group does not exceed 1% of the outstanding shares of BP’s common stock.

Board of Directors’ Compensation

      Directors who are employed by us or are employees of BP do not receive a retainer or fees for service on our Board of Directors or any of its committees.

      Our independent directors receive an annual retainer of $120,000 and an annual committee retainer of $5,000 with respect to each committee on which they serve. An independent chairperson of our Board of Directors would receive an annual retainer of $200,000. An independent chairperson of our audit committee would receive an annual retainer of $25,000, and independent chairpersons of our compensation committee and our nominating and governance committee would each receive an annual retainer of $20,000 and $15,000,

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respectively, in each case in lieu of the $5,000 annual committee retainer to which ordinary committee members are entitled. All retainers are paid on a quarterly basis, with 50% in cash and 50% in stock.

      Each of our directors is entitled to be reimbursed for reasonable out-of-pocket expenses incurred in attending board or committee meetings and for other reasonable expenses related to the performance of his or her duties as a director.

Executive Compensation

      The following table discloses compensation information for 2004 for our chief executive officer and those of our other executive officers who were employed by BP in 2004 and are expected to be among our four most highly compensated employees in 2005, as determined by reference to their total salary and bonus for 2005. The compensation figures shown in the table reflect salaries paid by BP. Because Mr. Tomkins and Mr. Kleeman joined our company in May and June 2005, respectively, no summary compensation information has been provided for these individuals with respect to 2004.

Summary Compensation Table

	Annual compensation									Long-term compensation
										Awards				Payouts
												Securities		Long-term
							Other annual			Restricted		underlying		incentive			All other
Name	Year		Salary		Bonus		compensation			stock awards(1)		options(2)		plans(3)			compensation(4)
			($)		($)		($)					(#)		($)			($)
Ralph Alexander		2004		451,875		482,000		864,574	(5)		*		126,000		—			69,711
Didier Baudrand(6)		2004		337,367		147,970		384,720	(7)		*		42,000		65,085	(8)		9,126
Dennis Seith		2004		269,550		119,600		79,894	(9)		*		31,500		—			27,240

(1)	All awards of restricted stock made to the named executive officers in 2004 were payouts under BP’s 2001 LTPP and, accordingly, have been reflected in the column captioned “Payouts — long-term incentive plans”.
(2)	ADSs have been converted into shares at a ratio of one ADS for every six shares of BP common stock.
(3)	Payouts under long-term incentive plans represent awards of restricted shares of BP’s common stock or restricted stock units under BP’s 2001 LTPP. Under this plan, performance units were granted in 2001 and converted into an award of restricted shares of BP common stock or restricted stock units in 2004. See “— Awards of Performance Units Under the BP LTPP” for additional information with respect to these awards. Performance units are notional units that give participants the right to be considered for an award of restricted shares of BP common stock or restricted stock units (without payment by the participant) at the end of a three-year performance period if demanding performance conditions are met. Any restricted shares of BP common stock or restricted stock units awarded are held in trust for three years before they are released to the individual. In addition, shares are released at the end of the retention period only if BP’s minimum shareholding guidelines are met.
(4)	“All other compensation” includes amounts contributed or credited by BP to Mr. Alexander’s and Mr. Seith’s respective BP savings plan accounts and life, death and disability insurance premiums paid by BP for Mr. Baudrand in 2004. The insurance premium payments have been converted from euros to U.S. dollars at the noon buying rate published by the U.S. Federal Reserve Bank in New York for December 31, 2004, which was $1.3538 per €1.00.
(5)	Represents $455,896 in perquisites and other expatriate-related or personal benefits provided to Mr. Alexander and a restricted share award under BP’s 2001 LTTP on February 11, 2004, which was deferred at the election of Mr. Alexander. The restricted share award was made in the form of BP ADSs and for purposes of this table has been valued based on the price of one BP ADS on the award date, which was $47.92.
(6)	Mr. Baudrand’s salary and bonus have been converted from euros to U.S. dollars at the noon buying exchange rate published by the U.S. Federal Reserve Bank in New York for December 31, 2004, which was $1.3538 per €1.00.
(7)	Represents perquisites and other expatriate-related or personal benefits provided to Mr. Baudrand in 2004. The payments were made in a combination of U.S. dollars, euros and British pounds and have been converted from euros and British pounds to U.S. dollars at the noon buying rates published by the U.S. Federal Reserve Bank in New York for December 31, 2004, which were $1.3538 per €1.00 and $1.9160 per £1.00, respectively.
(8)	Represents the fair market value of a restricted share award under BP’s 2001 LTPP on February 11, 2004. The restricted share award was made in the form of shares of BP common stock and for purposes of this table has been valued based on the price of one share of BP common stock on the award date, which was £4.14. The value has been converted from British pounds to U.S. dollars at the noon buying rate published by the U.S. Federal Reserve in New York on the grant date, which was $1.885 per British pound.

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(9)  Represents the fair market value of a restricted share award to Mr. Seith under BP’s 2001 LTPP on February 11, 2004, which was deferred at the election of Mr. Seith. The restricted share award was made in the form of BP ADSs and for purposes of this table has been valued based on the price of one BP ADS on the award date, which was $47.92.

     The following table discloses compensation information for 2005 for our chief executive officer and our four executive officers (other than our chief executive officer) who are expected to be our most highly compensated employees in 2005, as determined by reference to their expected total salary and target bonus, for that of July 1, 2005.

Summary Future Compensation Table

					Grant date value of
					shares of common
					stock restricted
					stock units and
					shares underlying
Name	Salary		Target bonus(1)		options(2)
	($)		($)		($)
Ralph Alexander		750,000		1,200,000		2,600,000
Mark Tomkins		450,000		675,000		1,575,000
Didier Baudrand(3)		365,850		402,436		902,625
Henry Kleeman		350,000		525,000		1,225,000
Dennis Seith		305,000		335,500		752,500

(1)	The target figures shown in this column represent the amounts on which the calculation of the respective executive officer’s bonus will be based if certain performance targets are reached. These amounts are subject to upward or downward adjustment based on various criteria, including the achievement of goals established under our Accelerator program.
(2)	Upon consummation of the offering, each of the persons shown in the table will receive a combination of restricted shares of our common stock (or restricted stock units) and stock options under the Executive Share Matching Plan and the Incentive Plan. Dollar amounts shown in this column represent the estimated fair value of these awards on the grant date. See “— Innovene Incentive Plan 2005” and “— Innovene Executive Share Matching Plan” for more information on restricted cash grants made, and restricted shares (or restricted stock units) and stock options issued, under these plans.
(3)	Mr. Baudrand’s salary and target bonus amounts have been converted from euros to U.S. dollars at the noon buying rate published by U.S. Federal Reserve Bank in New York for August 1, 2005, which was $1.2195 per €1.00.

Grants of Options to Acquire Shares of BP Common Stock

      The following table discloses information regarding options with respect to shares of BP common stock granted to the executive officers named in the Summary Compensation Table in 2004.

	Number of shares									Potentially realizable value at
	of BP common									assumed annual rates of
	stock underlying		Percent of total							stock price appreciation over
	options/ stock		options/ SARs							option term(2)
	appreciation		granted to BP		Exercise
Name	rights (SARs)(1)		employees		price(1)			Expiration date		5%			10%
	(#)		(%)		($/£)					($/£)			($/£)
Ralph Alexander		126,000		0.171	$	8.09			February 24, 2014	$	3,845,552.30		$	9,745,384.50
Didier Baudrand		42,000		0.057		£4.22	(3)		February 25, 2014		£111,465.28	(4)		£282,474.91	(4)
Dennis Seith		21,000		0.029	$	8.09			February 24, 2014	$	392,901.92		$	995,690.60
		10,500		0.014	$	9.92			December 6, 2014	$	640,925.38		$	1,624,230.80

(1)	ADSs have been converted into shares at a ratio of one ADS to six shares of BP common stock, and exercise prices have been adjusted accordingly.
(2)	Potentially realizable values have been determined assuming the stock options will be exercised at the end of their ten-year life.
(3)	This amount would correspond to $8.09, assuming conversion at the noon buying rate published by the U.S. Federal Reserve Bank in New York for December 31, 2004, which was $1.9160 per £1.00.
(4)	The potentially realizable values shown for Mr. Baudrand would correspond to $213,567.48 and $541,221.93, respectively, assuming conversion at the noon buying rate published by the U.S. Federal Reserve Bank in New York for December 31, 2004, which was $1.9160 per £1.00.

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Exercises of Options to Acquire Shares of BP Common Stock

      The following table discloses information regarding options with respect to shares of BP common stock exercised by the executive officers named in the Summary Compensation Table in 2004.

					Number of BP shares				Value of unexercised in-the-
					underlying unexercised				money options at
	BP shares				options at year-end				December 31, 2004(2)
	acquired on		Value
Name	exercise(1)		realized		Exercisable		Unexercisable		Exercisable		Unexercisable
	(#)		($)		(#)				($/£)
Ralph Alexander		—		—		395,444		286,020	$	1,335,220	$	748,671
Didier Baudrand		—		—		53,200		95,200		—		£99,960
Dennis Seith		20,640		121,484		68,940		58,200	$	111,114	$	124,880

(1)	ADSs have been converted into shares at a ratio of one ADS to six shares of BP common stock.
(2)	Options have been treated as “in the money” if their exercise price at December 31, 2004 was less than the market price of a share of BP common stock at that date. Option values have been calculated based on the closing price of a share of BP common stock or ADS, as reported on the NYSE or the London stock exchange on December 31, 2004, which were £5.08 and $58.40, respectively.

Awards of Performance Units Under BP’s LTPP

      The following table discloses information regarding grants of performance units under BP’s LTPP to the executive officers named in the Summary Compensation Table in 2004. Under the Conversion Plan, each of these executive officers has agreed to convert unvested performance units granted to him under BP’s LTPP in 2004 into Innovene restricted stock units. See “Innovene “BP LTPP” Conversion Plan” for more information regarding this plan.

						Estimated future payouts under
	Number of					non-stock price-based plans
	performance		Date of maturation
Name	units		or payout			Threshold		Target		Maximum
	(#)							(#)
Ralph Alexander		91,000		*(1)			—		91,000		182,000
Didier Baudrand		27,300		March 1, 2007(2	)		—		27,300		54,600
Dennis Seith		21,650		March 1, 2007(2	)		—		21,650		43,300

(1)	Performance units awarded to Mr. Alexander under BP’s 2004 LTPP are scheduled to be paid out in the form of BP ADSs ten years after the completion of his employment at BP.
(2)	Represents the date on which the performance units granted under BP’s 2004 LTPP are expected to result in an award of restricted stock.

Innovene Equity-Based Compensation Plans

      In connection with the offering, we have adopted the Conversion Plan, the Incentive Plan and the Executive Share Matching Plan to attract, retain and motivate our executive officers, certain key employees and others and align their financial interests with those of our shareholders. These plans are unfunded, are not qualified under Section 401(a) of the United States Internal Revenue Code and are not subject to the provisions of U.S. Employee Retirement Income Security Act. The following plan summaries are not complete and are qualified in their entirety by reference to the actual plans, copies of which are filed as exhibits to the registration statement of which this prospectus is a part.

      The plans will be administered by our compensation committee or any other committee designated by our Board of Directors. Our compensation committee has the exclusive power to administer the plans and to take all actions that are specifically contemplated in the plans or are necessary or appropriate in connection with their administration.

      If we subdivide or consolidate the outstanding shares of our common stock, declare a stock dividend or undertake a stock split, our compensation committee is authorized to make appropriate adjustments to (1) the number of shares of our common stock reserved under the plans, (2) the number of shares of our common stock covered by outstanding awards, (3) the exercise or other price in respect of such awards, (4) the appropriate fair

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market value and other price determinations for such awards and (5) the award limitations applicable to the Executive Share Matching Plan, as described below.

Innovene “BP LTPP” Conversion Plan

      Under the Conversion Plan, if the offering is completed on or before December 29, 2006, those of our executive officers and key employees who were awarded performance units under BP’s LTPP in 2003 or 2004 will have any unvested performance units exchanged for restricted stock units with respect to shares of our common stock. Each participant’s unvested performance units will be valued on the date of the offering as the equivalent of two shares of BP common stock, using the highest single closing price for these shares as reported on the London stock exchange during the five trading days prior to the offering and converted from British pounds into U.S. dollars value using the exchange rate on the close of business on the date of the offering. Each participant’s performance units will then be converted into restricted stock units at a ratio calculated by dividing the deemed value of one performance unit by the initial public offering price of our shares. The restricted stock units will vest on the third anniversary of the completion of the offering and entitle their holders to receive one share of our common stock of our for each restricted stock unit held by them, subject to certain transfer restrictions imposed by our compensation committee.

      We have reserved                      shares of our common stock for issuance under the Conversion Plan. The number of shares authorized to be issued under the plan is subject to adjustment in certain circumstances, as described under “— Innovene Equity-Based Compensation Plans.” Shares subject to awards that are forfeited, terminated or settled in cash instead of shares of our common stock, will no longer be reserved and will not again be available for awards under the Conversion Plan.

      If a participant ceases to be employed by us, any unvested restricted stock units held by him or her will lapse. However, if a participant ceases to be employed by us because of death, disability, retirement, termination by us without cause, termination by the participant for good reason, such as a significant change in his or her duties that could lead to an adverse change in the participant’s responsibilities or a reduction in his or her salary, or a participant’s employer ceasing to be our affiliate, the participant’s restricted stock units will vest immediately.

      During the vesting period, participants are entitled to cash dividend equivalents in respect of the number of shares represented by the restricted stock units held by them. A cash dividend equivalent represents an entitlement to receive upon vesting of a restricted stock unit any cash dividends paid on the underlying share of common stock during the vesting period. Restricted stock units do not entitle participants to exercise voting rights or receive any other types of dividend equivalents with respect to the underlying shares.

      At our compensation committee’s discretion, restricted stock units generally may be settled by a cash payment in an amount equal to the fair market value of the number of shares of our common stock underlying those units on the date of vesting or date of payment, as determined by the compensation committee.

Innovene Incentive Plan 2005

      To incentivize our executive officers and key employees, we launched the Incentive Plan in 2005. Because there was no public trading market for our common stock prior to the offering, no shares have been granted under the Incentive Plan. Instead, each participant received a restricted cash grant equal to a multiple of the participant’s basic annual salary. If the offering is completed on or before December 29, 2006, the restricted cash grant will lapse and be replaced by an award of restricted shares of our common stock and stock options. Restricted shares are shares that are subject to transfer restrictions and forfeiture during a vesting period. In some jurisdictions, we may grant participants restricted stock units instead of restricted shares. The number of restricted shares or restricted stock units issuable to a participant under the Incentive Plan will be equal to 30% of the participant’s restricted cash grant divided by the initial public offering price of our shares. The restricted shares or restricted stock units will vest on January 1, 2008. The number of stock options issuable to participants will be equal to five multiplied by the quotient of 70% of the restricted cash grant and the initial public offering price of our shares. The stock options will vest on January 1, 2008 and entitle their holders to purchase one share of our common stock for each stock option held by them at a price equal to the initial public offering price of our shares. In

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addition, the Incentive Plan provides for the grant of SARs to participants either in connection with the grant of stock options or separately.

      We have reserved                      shares of our common stock for issuance under the Incentive Plan. The number of shares authorized to be issued under the plan is subject to adjustment in certain circumstances, as described above under “— Innovene Equity-Based Compensation Plans.” Shares subject to awards that are forfeited or terminated, or settled in cash instead of shares of our common stock, will no longer be reserved and will not again be available for awards under the Incentive Plan.

      If a participant ceases to be employed by us, any unvested restricted shares, restricted stock units and stock options held by him or her will lapse. However, if a participant ceases to be employed by us because of death, disability, retirement, termination by us without cause, termination by the participant for good reason, such as a significant change in duties that could lead to an adverse change in the participant’s responsibilities or a reduction in salary, or a participant’s employing entity ceasing to be our affiliate, then his or her restricted shares, restricted stock units and stock options will vest immediately. A vested stock option generally will remain exercisable until it expires. However, stock options generally will expire and cease to be exercisable 60 days following termination of employment, except that if a participant dies, becomes disabled or is terminated without cause or terminates for good reason, or if the participant’s employing entity ceases to be a member of the group, his or her stock options will expire on the third anniversary after the relevant event.

      During the vesting period, participants are entitled to cash dividends with respect to restricted shares and cash dividend equivalents in respect of the number of shares represented by the restricted stock units held by them. Restricted shares also entitle participants to exercise voting rights with respect the underlying shares. No cash dividend or voting rights are associated with stock options.

      At our compensation committee’s discretion, restricted shares and restricted stock units generally may be settled by a cash payment in an amount equal to the fair market value of the relevant number of shares as of the date of vesting or the date of delivery, as determined by the committee. Likewise, at the compensation committee’s discretion, stock options generally may be settled by a cash payment in an amount equal to the difference between the fair market value of the number of shares of our common stock underlying the options on the date of exercise and the exercise price of the award.

Innovene Executive Share Matching Plan

      We have adopted a compensatory benefit plan under which we intend to offer our executive officers and key employees an opportunity, at the time of the offering to purchase shares of newly issued common stock at the initial public offering price and in addition receive stock options under the Executive Share Matching Plan. The maximum number of shares that each participant will be permitted to purchase will be equal to one-half of his or her basic annual salary at the time of purchase. Shares purchased under the plan will be subject to transfer restrictions for a period of up to 180 days from the date of purchase and certain additional transfer restrictions for up to one year from the date of purchase or, if earlier, the date the participant ceases to be our employee. The number of shares underlying each stock option granted will equal five times the number of shares purchased by the executive in connection with the offering. The stock options will have an exercise price equal to the initial offering price, a term of ten years and a vesting period of three years from the date of purchase and otherwise will have the same terms and conditions as stock options granted under the Incentive Plan, as described above under “— Innovene Incentive Plan 2005.”

      We have reserved                      shares of our common stock for issuance under the Executive Share Matching Plan. The number of shares authorized to be issued under the plan is subject to adjustment in certain circumstances as described under “— Innovene Equity-Based Compensation Plans.” Shares subject to awards that are forfeited or terminated, or settled in cash instead of common stock, will no longer be reserved and will not again be available for awards under the Executive Share Matching Plan.

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Retirement Plans

      The executive officers named in the Summary Compensation Table participate in various pension and other post-employment benefit plans sponsored by BP or us. In those cases where a plan is currently sponsored by BP, we intend to set up and sponsor corresponding plans once BP’s ownership of our common stock drops below certain levels, at which point our employees will no longer be entitled to participate in these plans.

      Mr. Alexander, Mr. Kleeman, Mr. Seith and Mr. Tomkins are covered by various U.S. retirement plans. Mr. Baudrand is covered by a French retirement plan.

U.S. Retirement Plans

      Mr. Alexander and Mr. Seith participate in the BP Retirement Accumulation Plan (RAP). Under this plan’s “cash balance” formula, participants earn monthly pay credits based on their eligible compensation (salary plus bonus), age and years of service, subject to a maximum of 11% of eligible compensation. Accumulated pay credits accrue interest at U.S. Treasury interest rates, with a minimum of 5% per year. As a former Amoco employee, Mr. Seith also accrues benefits pursuant to the grandfathered Amoco plan formula under the RAP. Mr. Seith’s total pension benefit will be the greater of the benefit to which he is entitled pursuant to the “cash balance” formula and the benefit to which he is entitled under the Amoco plan formula. The Amoco plan formula provides for an annual annuity to be paid from the time a participant reaches the age of 65. The annuity amounts to 1.67% of the participant’s final average earnings times years of service, offset by a portion of his or her social security benefits. A participant’s final average earnings are determined by calculating the sum of the participant’s average basic earnings during his or her three highest consecutive years of basic earnings and his or her average bonus awards during his or her three highest consecutive years of bonus awards. Mr. Tomkins and Mr. Kleeman participate in the BP Polyethylene Pension Plan, which mirrors the structure of the RAP.

      In addition, Mr. Alexander, Mr. Kleeman, Mr. Seith and Mr. Tomkins participate in the BP Supplemental Executive Retirement Benefit plan (SERB), which is an unfunded “top-up” arrangement for certain members of senior management. The benefits payable upon retirement under the SERB equal 1.3% of a participant’s final average earnings times years of service, with an offset for benefits payable under any other qualified and non-qualified pension plan of BP, including the RAP and the BP Polyethylene Pension Plan. A participant’s final average earnings are determined in the same manner as described above under the RAP. Benefits are payable in the form of a lump sum.

      Mr. Alexander, Mr. Kleeman, Mr. Seith and Mr. Tomkins are also eligible to participate in the BP Employee Savings Plan, a qualified savings plan which matches 100% of an employee’s contributions for the first 7% of his or her eligible compensation, including bonuses. Unfunded non-qualified plans have been established to enable matching contributions that could not be made under the qualified savings plan due to applicable IRS limits.

      At June 30, 2005, Mr. Alexander and Mr. Seith had accrued 22.75 and 27.08 years of service and estimated lump sum benefits upon retirement of $2,193,251 and $1,034,591, respectively, assuming no future growth in their final average earnings, which, as of June 30, 2005, were expected to be $893,709 and $405,375, respectively. Savings plan balances for Mr. Alexander and Mr. Seith, both qualified and non-qualified as of June 30, 2005, were $1,751,208 and $1,022,133, respectively. Mr. Tomkins and Mr. Kleeman joined our company in May and June 2005, respectively and do not currently have any accrued pension benefit entitlements under any company plans.

French Retirement Plans

      Mr. Baudrand participates in BP’s Caisse de Retraite plan, a partially funded non-contributory pension plan which “tops up” (but is not dependent on the future development of) state and mandatory benefit arrangements to provide annual retirement benefits depending on final earnings and years of service. Under the plan’s formula, benefits cannot exceed 65% of final base salary, inclusive of state and mandatory benefits. The normal retirement age under this plan is 60.

      At June 30, 2005, Mr. Baudrand had accrued 25.5 years of service and estimated benefits upon retirement, payable in the form of an annual annuity, of $7,500 per month, assuming no future growth in his final earnings.

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Change in Control Severance Agreements

      We intend to enter into change in control severance agreements with Mr. Alexander, Mr. Baudrand, Mr. Seith and certain other executive officers to provide severance pay and benefits in the event that their employment with us were to terminate under certain change in control scenarios defined in the agreement. The change in control severance agreements have similar terms and terminate on the earliest of (1) the relevant executive officer’s termination of employment, unless such termination is a qualifying termination as defined below or (2) December 31, 2007; provided that if a change in control occurs during this period, the term of the agreement will continue for an additional two years after such change in control. Mr. Alexander’s change in control agreement will be entered into by BP and it is expected that BP will assign this agreement to us following the consummation of the offering.

      A qualifying termination means (1) a termination of employment by us or our successors other than for cause or (2) a termination by the relevant executive officer for good reason, as defined in the applicable change in control agreement. Termination because of death, disability or retirement does not constitute a qualifying termination.

      A termination of employment by us other than for cause within the 90-day period preceding a change in control is deemed to be a qualifying termination and entitles the relevant executive officer to the benefits payable as if a change in control had occurred provided that such benefits will be offset by any severance payments or benefits payable to that executive officer as a result of his or her termination.

      Under the change in control severance agreements, if an executive officer becomes subject to a qualifying termination during the time period commencing with a change in control and ending two years after such change in control, we will generally provide him or her the following severance benefits:

• a lump sum cash payment equal to (1) twice the sum of the executive officer’s current annual base salary, plus the greater of (a) the executive officer’s current-year target bonus and (b) his or her most recent actual annual bonus and (2) an amount equal to the daily pro rata portion of the executive officer’s annual target bonus for the year of termination (subject to certain performance-based parameters if the termination occurs in 2005); if the executive officer terminates his or her employment because of a reduction in base salary or target bonus opportunity, then the base salary or target bonus amount prior to such reduction will be used in calculating the lump sum cash payments;

• twelve months of medical benefits (if the executive elects extended medical coverage) and group term life insurance;

• job placement services with a provider selected and paid by us for a period no less than one year; and

• certain gross-up payments in the event the executive officer is subject to the golden parachute excise tax under Section 4999 of the Internal Revenue Code.

      If Mr. Alexander experiences a qualifying termination under his change in control agreement prior to January 1, 2008, he will in addition be entitled to a lump sum benefit equal to no less than $3,210,000 for his participation in our and BP’s defined benefit pension plans.

      During the one year-period following a qualifying termination, each relevant executive officer will be subject to certain restrictions on competition with us (and in, certain limited circumstances, BP) and solicitation of our employees, customers and suppliers. In addition, the executive officer must maintain the confidentiality of BP’s and our non-public information.

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PRINCIPAL SHAREHOLDER

      Prior to the offering, all of the outstanding shares of our common stock were owned by BP. After the offering, BP will own           % of the outstanding shares of our common stock, assuming the underwriters do not exercise their option to purchase additional shares. Except for BP, we are not aware of any person or group that will beneficially own more than 5% of our outstanding shares of common stock following the offering. None of our executive officers, directors or director nominees currently owns any shares of our common stock, but those who own shares of BP common stock will be treated on the same terms as other holders of BP stock in any distribution by BP.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Overview of Arrangements Between Us and BP

      In connection with our separation from BP, we and BP have entered into numerous agreements. These agreements comprise:

•  reorganization agreements under which BP has transferred substantially all of the assets and liabilities comprising our current business activities to us, subject to the retention by BP of certain historic liabilities; and

•  commercial interface agreements which (1) have established arm’s length commercial arrangements between us and BP and (2) require BP to provide us with support services for a limited period of time.

      The reorganization agreements assume that our separation from BP and the transfer of all relevant assets and liabilities occurred on April 1, 2005, whereas the commercial interface agreements regulate our commercial relationships with BP with effect from January 1, 2005.

Reorganization Agreements

Local Transfer Agreements

      Effective April 1, 2005, BP transferred to us substantially all of the assets and liabilities relating to the former olefins and derivatives business of BP’s Petrochemicals segment, our refineries at Grangemouth, United Kingdom, and Lavéra, France, which formed part of BP’s Refining and Marketing segment, and the gas fractionator located near Hobbs, New Mexico, which formed part of BP’s Gas, Power and Renewables segment, in each case, together with associated infrastructure. The transfers were made on the basis of a series of Local Transfer Agreements. As a result of these transfers, we acquired BP’s title or other interest in the relevant assets and, with limited exceptions, the unencumbered ability to operate and transfer these assets to third parties.

      However, given the scale and complexity of our business, some transfers were structured differently to facilitate the relevant transaction and to protect the interests of one or both parties. The most important examples of such transfers are:

•  Pasadena, Texas. Instead of transferring BP’s facility in Pasadena, Texas to us, BP has agreed to operate the facility for us on a toll manufacturing basis and to close it in late 2005.

•  Wingles, France. Due to restrictions on the transferability of BP’s facility in Wingles, France, BP has retained ownership of that facility. However, we have entered into agreements with BP under which BP has agreed to purchase all of the facility’s styrene requirements from us, and to sell all of the polystyrene and EPS made by the facility to us. Following the commencement of operations of our polystyrene and EPS joint venture with NOVA, we expect to supply approximately half of the styrene requirements of that joint venture, which in turn will supply all of the Wingles facility’s styrene requirements. The joint venture will also purchase all of the polystyrene and EPS made by the Wingles facility. In addition, we have entered into a put and call option agreement with BP, under which we have the option to purchase and transfer to the joint venture, and BP has the option to sell to the joint venture, the Wingles facility and associated assets and liabilities, in each case at the fair market value of the facility and related assets and liabilities at the time of transfer. Our call option is exercisable in January 2007. If we do not exercise the option at that time, BP may exercise its put option in February 2007.

•  Grangemouth, United Kingdom. BP has retained ownership of certain assets of our Grangemouth, United Kingdom, site, including the power station, two of the high voltage electricity substations and certain tankage and pipelines associated with the transportation of condensate from Grangemouth to other destinations, to ensure that the FPS remains in operation throughout the term of certain supply agreements between us and BP at that site. BP has agreed to lease these assets to us on a long-term basis. Under the terms of the leasing arrangement, BP has reserved the right to temporarily step in as operator of the leased assets in the event this is necessary to protect itself against our failure to take off hydrocarbons from, or to provide utilities to, BP or otherwise fail to transport condensate through the relevant pipelines. BP is

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	entitled to terminate the leasing arrangement if we become insolvent or materially breach our various Framework Interface Agreements (FIAs) with BP with respect to that site.
•	Pipelines in North America. We have entered into a 50/50 joint venture with BP in relation to certain pipelines in Texas. This joint venture lasts until December 31, 2025, unless it is terminated earlier. In addition, certain other pipelines are wholly-owned by us and operated by BP on our behalf under arrangements which expire on December 31, 2006.
•	RMR Pipeline Access. A significant portion of the annual naphtha supply required by the petrochemical cracker at our Cologne, Germany, site is transported through the RMR pipeline. BP is entitled to a certain amount of RMR pipeline capacity every year, consistent with its overall 35% interest in the pipeline. We have agreed with BP to use some of this capacity, along with associated infrastructure at Nerefco, The Netherlands, to enable us to meet approximately 50% of the current naphtha requirements of our Cologne site.

      In instances where a third party consent would have been necessary to transfer an asset from BP to us but was not obtained, we and BP have agreed to alternative arrangements so that, to the maximum extent possible, we will receive the same benefits as if the consent had been obtained.

Amended and Restated Master Reorganization Agreement

      The Amended and Restated Master Reorganization Agreement sets out a framework for dealing with assets or liabilities not specifically covered by the Local Transfer Agreements described above, such as liabilities arising from our or BP’s past and future conduct.

      Subject to the exceptions described below, we generally have assumed all liabilities relating to the businesses and assets BP has transferred to us, and BP has agreed to retain all liabilities relating to the businesses and assets it has retained. In each case, these indemnities cover all losses arising from such liabilities, regardless of whether they arise from events occurring before or on or after April 1, 2005.

      Notwithstanding this overall allocation of liabilities, BP has specifically agreed to indemnify us, subject to certain limitations, for claims and losses relating to:

•  any liabilities related to off-site waste disposal prior to April 1, 2005 (excluding liabilities related to certain waste disposal sites located near our facilities in Cologne, Germany, and Sarralbe, France);

•  any liabilities related to former facilities which, as of April 1, 2005, had been sold, closed or decommissioned;

•  any claims for exposure to hazardous materials at our facilities to the extent that such claims were either made prior to April 1, 2005 or threatened in writing prior to April 1, 2005 and made prior to April 1, 2006 or, in certain cases, to the extent that such exposure related to events that occurred prior to April 1, 2005; and

•  certain product liability claims related to products manufactured prior to April 1, 2005;

      The Amended and Restated Master Reorganization Agreement provides that we will maintain employee benefits at the same or comparable levels for a period of at least twelve months from the date of the consummation of the offering. With respect to retirement benefit arrangements, in particular, we plan to meet this commitment by either continuing to participate in BP’s arrangements after the date of consummation of the offering for a prescribed period or by establishing replacement pension, saving and post-employment medical plans. With respect to funded retirement benefit arrangements being retained by BP, BP has agreed to transfer to us the relevant plan assets relating to our employees together with associated liabilities that accrued prior to the date of the offering and to make any necessary equalization payments to ensure that the sum of the value of these plan assets and the amount of these payments equals the amount of the liabilities transferred to us. Our employees may continue to participate in BP’s retirement plans until BP’s stake in our company falls below certain thresholds. The relevant threshold is 80% with respect to our U.S. employees and 50% with respect to all our other employees. Our U.K. and Belgian employees may continue to participate in BP’s retirement plans until the

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later of the date on which BP’s stake in our company falls below 50% or the expiration of twelve months from the consummation of the offering.

Intellectual Property and Information Technology Separation Agreement

      We have entered into an Intellectual Property and Information Technology Separation Agreement (IPITSA) with BP, which governs the transfer of intellectual property and intellectual property related agreements from BP to us and addresses certain related third-party issues.

      The IPITSA provides for the transfer from BP to us of certain registered patents, trademarks and domain names along with any other intellectual property relating exclusively to our petrochemical business, our refineries in Grangemouth, United Kingdom, and Lavéra, France, and our gas fractionator near Hobbs, New Mexico. In addition, BP has agreed to assign to us all intellectual property-related contracts, such as licenses, research and development agreements, technology sharing agreements, software licenses and support agreements relating exclusively to our business.

      BP has also granted us licenses in respect of certain intellectual property in which we and BP have a common interest. The terms and conditions of these licenses are set forth in separate common interest license agreements.

      Under the IPITSA, we have assumed all liabilities relating to the intellectual property and related contracts transferred from BP to us, whether existing at April 1, 2005 or arising thereafter. In this connection, we have agreed to indemnify BP for any losses it may incur in the event a third party raises a claim in respect of our use of any of this transferred intellectual property on or after April 1, 2005. In return, BP has agreed to indemnify us in the event and to the extent that we notify it before the end of September 2005 of any failure or inability to transfer a material intellectual property-related third-party contract to us or to extend a material common interest intellectual property agreement to cover our activities.

      BP has also transferred to us in separate agreements various U.S. and foreign trademarks, including our Innovene® brand. Pursuant to a separate endorsement agreement, BP has allowed us to describe ourselves as “forming part of the BP group” and to use certain BP trademarks in connection with this description, so long as BP holds 50% or more of our share capital. We have not been granted any other rights to use the “BP” trademark and are required to phase out all uses of this trademark on or before April 1, 2006.

Master Tax Agreements

      We have entered into two Master Tax Agreements with BP, one with respect to taxation in the United States (the U.S. Tax Agreement), and one with respect to taxation in the rest of the world (the ROW Tax Agreement).

U.S. Master Tax Agreement

      The U.S. Tax Agreement regulates the ongoing arrangements between us and BP in relation to U.S. tax matters, including the preparation and submission of tax returns and the conduct of tax audits and litigation. Under the U.S. Tax Agreement, BP has generally agreed to assume, and to indemnify us for, U.S. federal, state or local tax liabilities of our businesses arising on or before April 1, 2005, and U.S. federal, state or local tax liabilities of any BP entity not associated with our businesses arising after April 1, 2005. We have agreed to assume, and to indemnify BP for, any U.S. federal, state or local tax liabilities of our businesses arising after April 1, 2005.

      BP has also agreed to assume, and to indemnify us for, any U.S. federal, state and local tax liabilities arising as a result of our deconsolidation from BP. As a general matter, U.S. state or local transfer tax liabilities arising as a result of our legal separation from BP will be borne by the entity that is legally responsible for such taxes under applicable law. In addition, the U.S. Tax Agreement requires us to indemnify BP in the event that our actions cause a recapture of any dual consolidated loss incurred prior to the offering that is related to any business owned by us at the time of the offering. Moreover, each party to the U.S. Tax Agreement will be required under certain circumstances to pay compensation if one party uses a tax credit or loss generated by the other party.

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Rest of the World Tax Agreement

      Under the ROW Tax Agreement, BP has generally agreed to assume, and indemnify us for, non-U.S. tax liabilities arising prior to April 1, 2005, and we have generally agreed to assume, and indemnify BP for, non-U.S. tax liabilities arising on or after April 1, 2005. Any other separation-related non-U.S. tax liabilities generally will be paid by the party on which it has been assessed provided that taxes payable on the transfer of shares and assets will be borne by us. We will also be liable for any separation-related non-U.S. tax liabilities where the relevant tax is jointly payable by us and BP. The ROW Tax Agreement also regulates the ongoing relationship between us and BP in relation to other non-U.S. tax matters, for example, in relation to tax compliance, and includes provisions which allow both parties to share tax assets, subject to appropriate compensation payments.

Commercial Interface Agreements

      We have entered into a series of commercial interface agreements with BP to maintain and enhance our existing relationships by establishing medium- to long-term arrangements for services, utilities and infrastructure access rights in situations where we or BP depend on each other or where reasonable alternatives do exist but it is nevertheless economical for us and BP to continue preexisting arrangements. We have also established agreements for the sale and purchase of refining and petrochemical feedstocks and refined products in situations where we or BP have an interest in establishing a secure source of feedstock supply or ensure the off-take of products, with the term of these agreements in part depending on the availability of third-party alternatives. In addition, we have entered into various agreements for the provision by BP to us of short-term transitional services, such as information technology infrastructure, which we cannot readily replicate as a new company but which we expect to have the ability to provide in-house or outsource to a third party at the end of the initial term of these agreements.

      The commercial interface agreements include:

•  Hydrocarbons Sale and Purchase Agreements (SPAs);

•  Supply and Trading Agreements, which include the Master Services Agreements, the Sale and Purchase Agreements and the Foreign Exchange and Precious Metals Agreements;

•  Shipping Services Agreements;

•  Inland Refined Product Sale and Purchase Agreements;

•  FIAs, including the Utilities FIAs, Complex Infrastructure FIAs, Shared Services FIA and Functional Services FIAs; and

•  Site Cooperation Agreements.

      Set forth below is a summary of the key principles on which these commercial interface agreements are based. We believe that these principles will allow us to operate successfully as a standalone entity and maintain secure commercial relationships with BP.

      No stranding of key infrastructure. We have agreed with BP that when a term sheet under a Hydrocarbons SPA or site-based FIA expires neither party should be left stranded, land-locked or cut off from alternative sources of supply of the feedstock or service covered by the term sheet. Accordingly, upon expiration of a term sheet, the stranded party generally will be entitled to request the other party to allow it to access and use for a period of not more than five years any infrastructure owned by that party which it considers in good faith to be necessary for the continued supply or purchase, as applicable, of the relevant feedstock or service from the relevant third party.

      Pricing arrangements. Prices for the sale and purchase of petrochemical and refining feedstocks as between us and BP are generally based on formulas designed to reflect market prices. Services, utilities and complex infrastructure access rights provided to us by BP are generally priced at cost, which includes BP’s fixed and variable costs and, where fixed assets are involved in providing the service, a fixed return on capital investment.

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      Term and termination. The initial term of the commercial interface agreements and related term sheets generally runs from January 1, 2005. The medium- to long-term nature of many of these agreements allows us to secure the supply of products and services for which we may not have ready third-party alternatives and also reflects BP’s desire to have a guaranteed purchaser for certain of its products and services.

Hydrocarbons Sale and Purchase Agreements

      The Hydrocarbons SPAs govern the sale and purchase of petrochemical feedstocks at or between sites where we and BP have a continuing relationship with each other.

      Each of the agreements is in substantially the same form, with only minor jurisdiction- and site-specific differences. Each agreement is a master agreement describing the general terms and conditions on which the relevant feedstocks are sold and purchased as between us and BP. The commercial terms for each relevant petrochemical feedstock are set out in a separate term sheet appended to the relevant agreement.

      Neither the agreements themselves nor the relevant term sheets executed on the basis of these agreements may be terminated prior to the expiry of an initial term set forth in the relevant term sheet, unless a termination event or extended force majeure event occurs or the parties mutually agree to terminate the relevant term sheet. Termination events include breach of a material obligation, insolvency and failure to make any payment of an amount (other than an amount subject to a bona fide dispute) in excess of, in most cases, $500,000 when due and such amount is not paid for 60 days following notification by the other party. Unless terminated, most of the term sheets automatically renew at the end of their initial term.

      The most significant term sheets we have entered into with BP are discussed below.

      NGLs in South Houston, Texas. To address our and BP’s mutual requirements for the sale and purchase of NGLs at our Chocolate Bayou, Texas, site, we have entered into a term sheet for the purchase by us of NGLs provided by BP for processing at our gas fractionator near Hobbs, New Mexico, further processing at BP’s gas fractionator in Mont Belvieu, Texas, and the supply of the resulting gas to the olefins crackers of our Chocolate Bayou site. The NGL processing arrangements have an initial term of ten years, while the gas supply arrangements to our Chocolate Bayou site have a five-year initial term. All of the relevant term sheets are thereafter terminable on one year’s notice. If, prior to the end of the initial term, we become subject to a change in control (other than a change in control caused by BP), BP has the right to terminate these arrangements by providing notice in accordance with the notice period set forth in the term sheet.

      Propylene in Toledo, Ohio, Texas City, Texas, Whiting, Indiana, and Carson, California. We have entered into four term sheets for the purchase by us of propylene from BP’s refineries in Toledo, Ohio, Texas City, Texas, Whiting, Indiana, and Carson, California. The term sheet for the Carson facility has a five-year initial term and is thereafter terminable on two years’ notice, and the term sheet for the Toledo facility has a three-year initial term and is thereafter terminable on two years’ notice. The term sheets for the Texas City and Whiting facilities each have an initial term of three years with a notice period thereafter of one year.

      NGLs in Grangemouth, United Kingdom. Our Grangemouth, United Kingdom, site is connected with the FPS, which transports oil and gas from the North Sea to Scotland. BP stabilizes the oil and separates the associated gas at its Kinneil, Scotland, site, which is adjacent to our Grangemouth site and provides dry gas, propane, butane and condensate to Grangemouth. BP requires a constant off-take of these products and a constant supply of utilities to enable the FPS to continue in operation, and we depend on constantly purchasing feedstocks for our operations at the site. Accordingly, we have entered into a term sheet for the off-take of feedstocks from the FPS with an initial term of 13 years, which is thereafter terminable on three years’ notice. If, prior to the end of the initial term, we become subject to a change in control (other than a change in control caused by BP), BP has the right to terminate these arrangements by providing notice in accordance with the notice period set forth in the term sheet.

      Naphtha in Cologne, Germany. Our Cologne, Germany, site primarily uses naphtha as the feedstock for its cracker. Approximately one-third of the facility’s naphtha requirements is provided under a term sheet pursuant to which BP has agreed to supply naphtha from a facility in Nerefco, The Netherlands, via the RMR pipeline. The

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term sheet has an initial term of three years from January 1, 2005 and is thereafter terminable on two years’ notice.

Supply and Trading Agreements

      We have entered into various Supply and Trading Agreements with BP under which BP will, for a limited period of time, provide us with certain supply, trading and optimization services in areas in which we currently have no or only limited in-house capability. The agreements have been structured so as to enable us to develop the necessary capabilities in-house by the end of the initial term of these agreements. The main agreements may be divided into Master Services Agreements and Sale and Purchase Agreements. We have also entered into a series of Foreign Exchange and Precious Metals Agreements with BP for the provision of foreign exchange and interest rate services and services relating to the sale and/or lease of certain precious metals used as catalysts but because these agreements are less material, they are not described below.

Master Services Agreements

      We have entered into a series of Master Services Agreements with BP under which BP has agreed to provide us with certain commercial services where we currently have no or only limited in-house capability. We have entered into Master Services Agreements for:

•  commercial optimization services, including asset trading, cargo balancing and inventory and working capital management with respect to (1) naphtha, gas and benzene at our facilities in North America, (2) crude oil, feedstocks and refined products in Europe and (3) the trading of certain petrochemical products in Asia;

•  sale and purchase execution services for (1) naphtha and gas at our facilities in North America and (2) crude oil, feedstocks and refined products in Europe; and

•  various other services, such as inventory and excise tax accounting and invoicing services at our facilities in the United Kingdom and France.

      Each service provided under a Master Service Agreement may be terminated by either party. Notice periods range from three to twelve months, depending on the agreement, provided that in most cases no notice may be given prior to December 31, 2005. The termination of a particular type of service does not affect any contracts or agreements that have already been entered into between us and BP under one of the Master Services Agreements or any schedules entered into under the Sale and Purchase Agreements described below. The prices payable by us for the various types of services are set out in schedules to the relevant agreements and generally consist of a combination of a fixed fee and a value sharing element.

      Each agreement provides that, following a change in control, we and BP will enter into negotiations in good faith for a period of two months following the event to make any amendments necessary to enable us to comply with law. If no amendment is agreed, either party may terminate the agreement without liability to the party, except for certain mark-to-market termination payments that may be due in respect of certain terminated transactions.

      The various agreements remain in effect until a termination event, a change in control (as described above) or an extended force majeure event occurs. Termination events include breach of a material obligation, insolvency of either party and failure to make any payment in an amount (other than an amount subject to a bona fide dispute) greater than that set forth in the agreement when due for 60 days following notification by the other party.

Sale and Purchase Agreements

      We have also entered into a series of Sale and Purchase Agreements with BP under which BP has agreed to sell to, or purchase from, us crude oil, naphtha, gas and refined products purchased from, or to be sold to, a third party in situations where BP has the commercial relationship with the third party. Each agreement governs a different type of product. The agreements include an Amended and Restated Master Feedstock Sales and

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Purchase Agreement in respect of Crude Oil, an Amended and Restated Master Refined Products Sale and Purchase Agreement and two Amended and Restated Master Feedstock Sales and Purchase Agreement for Naphtha, NGL and Other Feedstock Volumes, including one for our facilities in Europe and one for those in the United States.

      None of the agreements has a fixed term. Instead, the agreements remain in effect until a termination event or a change in control occurs (as described above) or one of the parties terminates the agreement on twelve months’ notice at the end of a calendar year quarter. Termination events include breach of a material obligation, insolvency of either party or failure to make any payment in an amount greater than $10 million when due for 60 days following notification by the other party.

      For each trade or series of trades under an agreement, a separate schedule to the relevant agreement will be executed. Each schedule contains the specific terms associated with the relevant trade and incorporates by reference the relevant provisions of the underlying initiating contract, which is the contract under which BP has purchased the product to be sold to us or the contract under which BP will on-sell the product purchased from us. Termination of an agreement will not in itself affect schedules already executed.

Shipping Services Agreements

      We have entered into two Shipping Services Agreements with BP under which BP will, for a short transitional period, provide us with certain services where we currently have no or only limited in-house capability. The shipping services we receive from BP under these agreements include chemical movement services in Europe and container movement services in Asia. The services generally involve the negotiation of shipping contracts and charters, assistance with maintaining shipping supplier relationships, the provision of shipping market and price information and assistance with identifying and recruiting resources for building our own chartering capabilities. Each of the agreements is in substantially the same form, subject to service-specific and jurisdictional differences. The agreements were intended to be transitional in nature, and we have already terminated services under some of the agreements.

      We have also entered into a Global Assurance Services Agreement with BP under which BP will provide us with global assurance services for certain marine activities. These services include ship and shore interface audits, vessel owner audits, physical inspections of ships and barges and support services in case of marine emergencies. The agreement may be terminated, at our option, by providing not less than one month’s notice provided that such notice may not be given prior to June 30, 2005. BP may terminate the agreement in the event of a termination event, such an extended force majeure, or six months after BP ceases to have the power to remove or appoint a majority of our Board of Directors or otherwise control our affairs and policies. We are currently developing the necessary plans to obtain these services from non-BP sources before the possible occurrence of any termination event.

Inland Refined Products Sale and Purchase Agreements

      We have entered into Inland Refined Products Sale and Purchase Agreements with BP for the domestic sale of certain refined products. We have entered into separate agreements for our Grangemouth, United Kingdom, and Lavéra, France, refineries. Under each agreement, BP has agreed to purchase all of the refined products we sell into the relevant domestic market at market-based prices.

      The agreement with respect to our Grangemouth refinery leverages the refinery’s position in its domestic market by providing it with guaranteed access to BP’s distribution network in Scotland and northern England. Similarly, under the agreement with respect to our Lavéra refinery, the vast majority of the refinery’s products are sold domestically and the refinery’s guaranteed access to BP as a customer for its refined products in France under the relevant agreement should help to mitigate competitive pressures from other refineries in the region.

      The agreements remain in effect until a termination event or an event of extended force majeure occurs. Termination events include breach of a material obligation, insolvency of either party (but only in the case of the Grangemouth agreement) or failure to make any payment in an amount greater than $10 million when due for 60 days following notification by the other party.

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      Most of the term sheets under the Grangemouth agreement have fixed terms ranging from three to seven years. Most of the term sheets under the Lavéra agreement terminate between 2008 and 2011 and may generally be terminated upon written notice with notice periods ranging from one to three years, depending on the refined product.

      Under the Grangemouth agreement, we are required to sell our refinery products exclusively to BP, but only for so long as BP holds a majority of the voting rights in our company. If BP ceases to hold at least 50% of our voting rights, the exclusivity arrangements may be terminated by either party on twelve months’ notice from the earlier of the date that BP’s voting rights in us falls below 50% or January 1, 2007 (except in the case of jet fuel). Under the Lavéra agreement, we are required to sell our refinery products exclusively to BP, with certain limited exceptions. In return, BP has agreed to compensate us for the restraints that this exclusivity imposes on our business.

Framework Interface Agreements

General

      We have entered into various FIAs for the provision by us to and vice-versa BP of services and utilities at certain shared sites and in some cases between our respective sites. These agreements range from short-term, transitional arrangements for services which we will eventually establish on an in-house basis or will outsource to an alternative supplier to long-term arrangements in areas where we and BP depend on each other.

      The agreements may be categorized as follows:

•  Utilities FIAs, which govern arrangements for utility supply, including electricity, water and gas;

•  Complex Infrastructure FIAs, which govern access rights to infrastructure, such as jetties, pipelines and storage facilities at our facilities in Texas City, Texas, and Grangemouth, United Kingdom;

•  Shared Services FIAs, which govern shared services, such as laboratory services, medical services and facilities management services; and

•  Functional Services FIAs, which govern the provision of functions, such as information technology, accounting, human resources, tax, legal and health and safety services.

      Each agreement describes the general terms and conditions on which services are to be provided. The specific terms applicable to particular services are set forth in separate term sheets appended to the relevant agreement. Most of the term sheets continue on an evergreen basis and automatically renew, unless a termination event or extended force majeure event occurs prior to the expiration of the term.

      The services provided under the various agreements generally may be categorized as strategic, normal, transitional or pass-through.

      Strategic services are characterized by a high degree of mutual dependence between us and BP and the lack of viable alternatives. Strategic services include certain infrastructure-related services, such as marine, road or rail services, access to storage facilities and, generally, pipelines and key utilities. Strategic services are terminable by either party on 48 months’ notice, provided that no notice may be given prior to January 1, 2015.

      Transitional services are services provided on a temporary basis. Most of the services terminate no later than December 31, 2006, although certain term sheets are renewable until December 31, 2007. Examples of transitional services include the services provided under the Functional Services FIAs, such as employee training and ancillary facilities services. Transitional services are terminable at our option on six months’ notice or four months’ notice in the case of term sheets executed under the Functional Services FIAs.

      Pass-through services are services provided to either us or BP by a third party where the benefit of the service is “passed through” to the other party as the third party’s customer. Examples of such services include payroll services, corporate relationship services, security services and certain utility supplies. Pass-through services are terminable in accordance with the terms of the underlying third party pass-through contract.

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      Services that do not fall within any of these categories are categorized as “normal” services and include services where reasonable alternatives exist but where it is nevertheless economical for both parties to continue preexisting arrangements. Examples of this type of service include facilities management, medical services, security services, storehousing services, canteen services and fire brigade services. Most normal services are terminable by either party on 12 months’ notice provided that no notice may be given prior to January 1, 2008.

Utilities FIAs

      We have entered into Utilities FIAs with BP at our sites in Carson, California, Whiting, Indiana, and Texas City, Texas, in North America and Geel, Belgium and Grangemouth, United Kingdom, in Europe for the provision of certain utilities at cost-based prices. Depending on the type of utility, the initial term under the relevant term sheets ranges from one month to several years. The most significant term sheets include:

•  a five-year term sheet for the provision of gas fuel from BP to us in Texas City. The term-sheet can be terminated by BP on 30 days notice at any time and by us after December 31, 2009 on two years notice; and

•  ten-year term sheets with a four-year notice period for the provision of steam and power services from us to BP in Grangemouth.

Complex Infrastructure FIAs

      We have entered into Complex Infrastructure FIAs with BP at our sites in Texas City, Texas, and Grangemouth, United Kingdom, for the provision of certain access rights. Generally these rights are provided at cost. The term of the complex infrastructure term sheets ranges from two to 13 years. The most significant term sheets include:

•  a 13-year term sheet with a two-year notice period granting us long-term access to the LPG export/import terminals at our Grangemouth site; and

•  a 13-year term sheet granting BP long-term access to the condensate systems which we lease from BP near the Grangemouth site.

Shared Services FIAs

      We have entered into Shared Services FIAs with BP with respect to our sites in Grangemouth, United Kingdom, Hull, United Kingdom, and Geel, Belgium, in Europe and Carson, California, La Porte, Texas, Pasadena, Texas, Texas City, Texas, and Whiting, Indiana, in North America for the provision of certain shared services at cost-based prices. Most of the services provided under the Shared Services FIAs are normal, transitional or pass-through services and thus have initial terms ranging from two to five years with notice periods ranging from six to twelve months.

Functional Services FIAs

      We have entered into eight Functional Services FIAs under which BP has agreed to provide us with head office services at cost-based prices in areas such as information technology, accounting, human resources, tax, legal and health and safety, pending our development of internal capabilities in these areas. In some instances, we have agreed to provide functional services to BP where BP no longer has the relevant capabilities as a result of the separation.

      Agreements have been established for our sites in Belgium, Canada, France, Germany, the United Kingdom and the United States and for our operations in Asia. In addition, we have entered into separate agreements for certain administrative services provided from BP to our operations in the United States and Asia. The agreements are all in substantially the same form, subject to jurisdictional variations. The key commercial terms for each service to be provided are set forth in separate term sheets appended to the relevant agreements.

      All of the functional services are either transitional or pass-through in nature and terminate on or before December 31, 2006. We are entitled to terminate most transitional services at any time on four months’ notice.

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Following termination of a service, BP is generally required to use reasonable efforts to assist us in migrating the relevant service to a new service provider or an in-house function.

Site Cooperation Agreements

      We have entered into various Site Cooperation Agreements with BP to establish rules and procedures to facilitate our operations at certain key sites that we share with BP. We have agreements in place for our sites in Carson, California, Naperville, Illinois, Texas City, Texas, Whiting, Indiana, Geel, Belgium, and Grangemouth, United Kingdom.

      At each shared site, a site board has been established, which is comprised of one representative from us and one representative from BP. Each site board is responsible for governance and policy coordination (including the implementation and oversight of joint site rules), strategy and new developments, reputation and conflict resolution. Each site board is authorized to establish joint site committees responsible for matters relating to the relevant sites, such as HSSE matters.

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DESCRIPTION OF CAPITAL STOCK

      The following descriptions are summaries of material terms of our certificate of incorporation and bylaws as each will be in effect upon the completion of the offering. These descriptions may not contain all of the information that is important to you. To understand the material terms of our certificate of incorporation and bylaws fully, you should read our certificate of incorporation and bylaws, copies of which are filed with the SEC as exhibits to the registration statement of which this prospectus is a part. The following descriptions are qualified in their entirety by reference to the certificate of incorporation and bylaws and applicable law.

      Upon the completion of the offering, our authorized capital stock will consist of                      shares of common stock, par value $0.01 per share and                      shares of preferred stock, par value $0.01 per share. As of                     , 2005, there were                      shares of common stock outstanding, all of which were held by the BP group. Upon completion of this offering, we will have                      shares of common stock outstanding. In addition, as of                     , 2005, shares of our common stock were reserved for issuance under our stock option plans, and options to purchase                      shares of our common stock were outstanding.

Description of Common Stock

      We are authorized to issue one class of common stock. Our shareholders will be entitled to one vote for each share of our common stock held of record on all matters on which shareholders are entitled or permitted to vote. Our common stock will not have cumulative voting rights with respect to the election of directors. As a result, holders of a majority of the shares of our common stock voting for the election of directors can elect all the directors standing for election. Upon completion of this offering, BP will own a majority of the shares of our outstanding common stock. See “Principal Shareholder” and “Risk Factors — Risks Related to Our Relationship with BP.” Holders of our common stock will be entitled to receive dividends, if any, out of legally available funds when and if declared from time to time by our Board of Directors. See “Dividend Policy.” In the event of our liquidation, dissolution or winding up, the holders of our common stock will be entitled to share ratably in all assets remaining after payment of liabilities, subject to the rights of any then-outstanding preferred stock. Our common stock will have no preemptive, subscription or conversion rights, and there are no redemption or sinking fund provisions applicable to our common stock. The rights, preferences and privileges of holders of our common stock will be subject to, and may be adversely affected by, the rights of holders of shares of any series of preferred stock that we may designate and issue in the future. All outstanding shares of our common stock are fully paid and nonassessable and the shares of common stock offered hereby will be fully paid and nonassessable.

Anti-Takeover Effects of Provisions of Our Amended and Restated Certificate of Incorporation and Bylaws

      Certain provisions of our certificate of incorporation and bylaws that may have the effect of delaying, discouraging, or preventing a merger or acquisition that our shareholders may consider favorable, including transactions in which shareholders might receive a premium for their shares. These provisions include:

•  authorizing our Board of Directors to issue shares of preferred stock in one or more series and to fix the rights and preferences of the shares of any such series without stockholder approval;

•  providing that no more than one-third of the members of our Board of Directors stand for re-election by the stockholders at each annual meeting;

•  permitting the removal of a director from office only for cause and only by the affirmative vote of the holders of at least a majority of the shares of our capital stock entitled to vote;

•  vesting the Board of Directors with sole power to set the number of directors;

•  providing that any vacancy on the Board of Directors, however occurring, including a vacancy resulting from an enlargement of the board, may only be filled by vote of the directors then in office;

•  allowing a special meeting of the stockholders to be called only by a majority of the Board of Directors, the chairman of our Board of Directors, the president, the chief executive officer or BP (for so long as the BP group or any designated direct transferee beneficially owns at least 10% of the outstanding shares of our common stock);

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•  prohibiting stockholder action by written consent on or after the first date on which the BP group or any designated direct transferee of the BP group ceases to beneficially own at least 50% of the shares of our capital stock entitled to vote;

•  requiring the affirmative vote of the holders of at least 80% of the outstanding shares of our common stock to effect certain amendments to our charter or bylaws, for so long as the BP group or its designated direct transferee owns at least 10% of the outstanding shares of our common stock; and

•  requiring formal advance notice by shareholders for nominations for election to our Board of Directors or for proposing matters that can be acted upon at shareholders’ meetings, other than BP or any designated direct transferee of the BP group (so long as such person owns at least 10% of the outstanding shares of our common stock).

Limitation of Liability and Indemnification Matters

      As permitted by the Delaware General Corporation Law, our certificate of incorporation and bylaws contain provisions that limit or eliminate the personal liability of our directors for a breach of their fiduciary duty of care as a director. The duty of care generally requires that, when acting on behalf of a corporation, directors exercise an informed business judgment based on all material information reasonably available to them. Consequently, a director will not be personally liable to us or our shareholders for monetary damages for breach of fiduciary duty as a director, except for liability for:

•  any breach of the director’s duty of loyalty to us or our shareholders,

•  any act or omission not in good faith or that involve intentional misconduct or a knowing violation of law,

•  any act related to unlawful stock repurchases, redemptions or other distributions or payment of dividends, or

•  any transaction from which the director derived an improper personal benefit.

      The duty of loyalty generally requires that, when acting on behalf of a corporation, officers and directors act in the best interests of the corporation and its shareholders. In circumstances where an officer or director owes fiduciary duties to more than one entity it can be difficult for such person to satisfy duties of loyalty to both entities. Our bylaws provide that transactions that we enter into in which a director or officer has a conflict of interest are generally permissible so long as (1) the material facts relating to the director’s or officer’s relationship or interest as to the transaction are disclosed to our Board of Directors and a majority of our disinterested directors approves the transaction, (2) the material facts relating to the director’s or officer’s relationship or interest as to the transaction are disclosed to our shareholders and a majority of our disinterested shareholders approves the transaction, or (3) the transaction is otherwise fair to us.

      These limitations of liability do not affect the availability of equitable remedies such as injunctive relief or rescission.

      Additionally, as permitted by the Delaware General Corporation Law, our certificate of incorporation and bylaws provide that:

•  we shall indemnify our directors and officers to the fullest extent permitted by the Delaware General Corporation Law,

•  we shall advance expenses to our directors and officers in connection with a legal proceeding to the fullest extent permitted by the Delaware General Corporation Law, subject to limited exceptions, and

•  the rights provided in our certificate of incorporation and bylaws are not exclusive.

Transfer Agent and Registrar

      The transfer agent and registrar for our common stock is           .

Listing

      We have our common stock approved for quotation on the NYSE under the trading symbol “INV.”

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SHARES ELIGIBLE FOR FUTURE SALE

      Prior to the offering, there has been no public market for the shares of our common stock. The sale of a substantial number of shares of our common stock in the public market after the offering, or the perception that such sales may occur, could adversely affect our share price. Furthermore, because some of our shares will not be available for sale shortly after the offering due to the contractual and legal restrictions on resale described below, the sale of a substantial number of shares of our common stock in the public market after these restrictions lapse could adversely affect our share price and our ability to raise equity capital in the future.

      Upon completion of the offering, we will have            million shares of common stock outstanding.

      Of those shares, all of the shares of our common stock sold in the offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are purchased by “affiliates” as that term is defined in Rule 144 under the Securities Act. Any shares purchased by an affiliate may not be resold except in compliance with Rule 144 volume limitations, manner of sale and notice requirements, pursuant to another applicable exemption from registration or pursuant to an effective registration statement. The shares of our common stock held by BP are “restricted securities” as that term is defined in Rule 144 under the Securities Act. These restricted securities may be sold in the public market by BP only if they are registered or if they qualify for an exemption from registration under Rule 144 or Rule 144(k) under the Securities Act. These rules are summarized below.

Rule 144

      In general, under Rule 144 as currently in effect, starting 90 days after the date of this prospectus, a person or persons whose shares are aggregated, who have beneficially owned restricted shares for at least one year, including persons who may be deemed to be our “affiliates,” would be entitled to sell within any three-month period a number of shares that does not exceed the greater of:

•  1.0% of the number of shares of common stock then outstanding, which will equal approximately            million shares immediately after this offering; or

•  the average weekly trading volume of our common stock on the NYSE during the four calendar weeks before a notice of the sale on Form 144 is filed with the SEC.

      Sales under Rule 144 are also subject to certain manner of sale provisions and notice requirements and to the availability of certain public information about us.

Rule 144(k)

      Under Rule 144(k), a person who is not deemed to have been one of our “affiliates” at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner other than an “affiliate,” is entitled to sell these shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144.

Stock Issued Under Employee Plans

      We intend to file registration statements on Form S-8 under the Securities Act to register approximately        million shares of common stock issuable, with respect to options to be granted, or otherwise, under the Conversion Plan, the Incentive Plan and the Innovene Executive Share Matching Plan. Currently, there are no outstanding options to purchase shares of our common stock. These registration statements are expected to be filed following the closing of the offering. Shares issued upon the exercise of stock options after the effective date of the Form S-8 registration statements will be eligible for resale in the public market without restriction, subject to Rule 144 limitations applicable to affiliates.

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CERTAIN U.S. FEDERAL TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

      This section summarizes certain United States federal income and estate tax consequences of the ownership and disposition of common stock by a non-U.S. holder. You are a non-U.S. holder if you are, for United States federal income tax purposes:

•  a nonresident alien individual,

•  a foreign corporation, or

•  an estate or trust that in either case is not subject to United States federal income tax on a net income basis on income or gain from common stock.

      This section does not consider the specific facts and circumstances that may be relevant to a particular non-U.S. holder and does not address the treatment of a non-U.S. holder under the laws of any state, local or foreign taxing jurisdiction. This section is based on the tax laws of the United States, including the Internal Revenue Code of 1986, as amended, existing and proposed regulations, and administrative and judicial interpretations, all as of the date hereof. These laws are subject to change, possibly on a retroactive basis.

      If a partnership holds common stock, the United States federal income tax treatment of a partner will generally depend on the status of the partner and the tax treatment of the partnership. A partner in a partnership holding common stock should consult its tax advisor with regard to the United States federal income tax treatment of an investment in common stock.

      You should consult a tax advisor regarding the United States federal tax consequences of acquiring, holding and disposing of common stock in your particular circumstances, as well as any tax consequences that may arise under the laws of any state, local or foreign taxing jurisdiction.

Dividends

      If you are a non-U.S. holder of common stock, dividends paid to you are subject to withholding of United States federal income tax at a 30% rate or at a lower rate if you are eligible for the benefits of an income tax treaty that provides for a lower rate. Even if you are eligible for a lower treaty rate, we and other payors will generally be required to withhold at a 30% rate (rather than the lower treaty rate) on dividend payments to you, unless you have furnished to us or another payor:

•  a valid Internal Revenue Service Form W-8BEN or an acceptable substitute form upon which you certify, under penalties of perjury, your status as (or, in the case of a non-U.S. holder that is a partnership or an estate or trust, such forms certifying the status of each partner in the partnership or beneficiary of the estate or trust as) a non-United States person and your entitlement to the lower treaty rate with respect to such payments, or

•  in the case of payments made outside the United States to an offshore account (generally, an account maintained by you at an office or branch of a bank or other financial institution at any location outside the United States), other documentary evidence establishing your entitlement to the lower treaty rate in accordance with U.S. Treasury regulations.

      If you are eligible for a reduced rate of United States withholding tax under a tax treaty, you may obtain a refund of any amounts withheld in excess of that rate by filing a refund claim with the Internal Revenue Service.

      If dividends paid to you are “effectively connected” with your conduct of a trade or business within the United States, and, if required by a tax treaty, the dividends are attributable to a permanent establishment that you maintain in the United States, we and other payors generally are not required to withhold tax from the dividends, provided that you have furnished to us or another payor a valid Internal Revenue Service Form W-8ECI or an acceptable substitute form upon which you represent, under penalties of perjury, that:

•  you are a non-United States person, and

•  the dividends are effectively connected with your conduct of a trade or business within the United States and are includible in your gross income.

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      “Effectively connected” dividends are taxed at rates applicable to United States citizens, resident aliens and domestic United States corporations.

      If you are a corporate non-U.S. holder, “effectively connected” dividends that you receive may, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate or at a lower rate if you are eligible for the benefits of an income tax treaty that provides for a lower rate.

Gains on Disposition of Common Stock

      If you are a non-U.S. holder, you generally will not be subject to United States federal income tax on any gain that you recognize on a disposition of common stock unless:

•  the gain is “effectively connected” with your conduct of a trade or business in the United States, and the gain is attributable to a permanent establishment that you maintain in the United States, if that is required by an applicable income tax treaty as a condition for subjecting you to United States taxation on a net income basis,

•  you are an individual, you hold the common stock as a capital asset, you are present in the United States for 183 or more days in the taxable year of the sale and certain other conditions exist, or

•  we are or have been a United States real property holding corporation for United States federal income tax purposes and you held, directly or indirectly, at any time during the five-year period ending on the date of disposition, more than 5% of the common stock and you are not eligible for any treaty exemption.

      If you are a corporate non-U.S. holder, “effectively connected” gains that you recognize may also, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate or at a lower rate if you are eligible for the benefits of an income tax treaty that provides for a lower rate.

      We have not been, are not and do not anticipate becoming a United States real property holding corporation for United States federal income tax purposes.

Federal Estate Taxes

      Common stock held by a non-U.S. holder at the time of death will be included in the holder’s gross estate for United States federal estate tax purposes, unless an applicable estate tax treaty provides otherwise.

Backup Withholding and Information Reporting

      If you are a non-U.S. holder, you are generally exempt from backup withholding and information reporting requirements with respect to:

•  dividend payments and

•  the payment of the proceeds from the sale of common stock effected at a United States office of a broker, as long as the income associated with such payments is otherwise exempt from United States federal income tax, provided, in each case:

•  the payor or broker does not have actual knowledge or reason to know that you are a United States person and:

•  you have furnished to the payor or broker a valid Internal Revenue Service Form W-8BEN or an acceptable substitute form upon which you certify, under penalties of perjury, that you are (or, in the case of a non-U.S. holder that is a partnership or an estate or trust, such forms certifying that each partner in the partnership or beneficiary of the estate or trust is) a non-United States person, or

•  you have furnished to the payor or broker other documentation upon which it may rely to treat the payments as made to a non-United States person in accordance with U.S. Treasury regulations, or

•  you otherwise establish an exemption.

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      However, we, or a paying agent, are required to report payments of dividends on common stock on Internal Revenue Service Form 1042-S.

      Payment of the proceeds from the sale of common stock effected at a foreign office of a broker generally will not be subject to information reporting or backup withholding. However, a sale of common stock that is effected at a foreign office of a broker will be subject to information reporting and backup withholding if:

•  the proceeds are transferred to an account maintained by you in the United States,

•  the payment of proceeds or the confirmation of the sale is mailed to you at a United States address, or

•  the sale has some other specified connection with the United States as provided in U.S. Treasury regulations,

unless the broker does not have actual knowledge or reason to know that you are a United States person and the documentation requirements described above are met or you otherwise establish an exemption.

      In addition, a sale of common stock will be subject to information reporting if it is effected at a foreign office of a broker that is:

•  a United States person,

•  a controlled foreign corporation for United States tax purposes,

•  a foreign person 50% or more of whose gross income is effectively connected with the conduct of a United States trade or business for a specified three-year period, or

•  a foreign partnership, if at any time during its tax year:

•  one or more of its partners are “U.S. persons,” as defined in U.S. Treasury regulations, who in the aggregate own more than 50% of the income or capital interest in the partnership, or

•  such foreign partnership is engaged in the conduct of a United States trade or business,

unless the broker does not have actual knowledge or reason to know that you are a United States person and the documentation requirements described above are met or you otherwise establish an exemption. Backup withholding will apply if the sale is subject to information reporting and the broker has actual knowledge that you are a United States person.

      You generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed your United States federal income tax liability by filing a refund claim with the Internal Revenue Service.

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UNDERWRITING

      We and the underwriters named below have entered into an underwriting agreement with respect to the shares of our common stock being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of shares indicated in the following table. Goldman, Sachs & Co. and Morgan Stanley & Co. Incorporated are the representatives of the underwriters.

Underwriters	Number of shares
Goldman, Sachs & Co.
Morgan Stanley & Co. Incorporated
Lehman Brothers Inc
UBS Securities LLC
Total

      The underwriters are committed to take and pay for all of the shares being offered, if any are taken, other than the shares covered by the option described below unless and until this option is exercised.

      If the underwriters sell more shares than the total number set forth in the table above, the underwriters have an option to buy up to an additional                     shares from us to cover such sales. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above.

      The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by BP. Such amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase                     additional shares.

	No exercise	Full exercise
	($)
Per share
Total

      Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $          per share from the initial public offering price. Any such securities dealers may resell any shares purchased from the underwriters to certain other brokers or dealers at a discount of up to $          per share from the initial public offering price. If all the shares are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms.

      Prior to the offering, there has been no public market for the shares. The initial public offering price has been negotiated among us and the representatives. Among the factors to be considered in determining the initial public offering price of the shares, in addition to prevailing market conditions, will be our historical performance, estimates of the business potential and earnings prospects of us, an assessment of our management and the consideration of the above factors in relation to market valuation of companies in related businesses.

      An application has been made to list the common stock on the New York Stock Exchange under the symbol “INV.” In order to meet one of the requirements for listing the common stock on the NYSE, the underwriters have undertaken to sell lots of 100 or more shares to a minimum of 2,000 beneficial holders.

      In connection with the offering, the underwriters may purchase and sell shares of common stock in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Shorts sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ option to purchase additional shares from us in the offering. The underwriters may close out any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the

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price at which they may purchase additional shares pursuant to the option granted to them. “Naked” short sales are any sales in excess of such option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common stock in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common stock made by the underwriters in the open market prior to the completion of the offering.

      The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

      Purchases to cover a short position and stabilizing transactions may have the effect of preventing or retarding a decline in the market price of our common stock, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the common stock. As a result, the price of the common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued at any time. These transactions may be effected on the NYSE, in the over-the-counter market or otherwise.

      Each of the underwriters has represented and agreed that:

      (a) it has not made or will not make an offer of shares to the public in the United Kingdom within the meaning of section 102B of the Financial Services and Markets Act 2000 (as amended) (FSMA) except to legal entities which are authorised or regulated to operate in the financial markets or, if not so authorised or regulated, whose corporate purpose is solely to invest in securities or otherwise in circumstances which do not require the publication by us of a prospectus pursuant to the Prospectus Rules of the Financial Services Authority (FSA);

      (b) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of FSMA) to persons who have professional experience in matters relating to investments falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 or in circumstances in which section 21 of FSMA does not apply to us; and

      (c) it has complied with, and will comply with all applicable provisions of FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

      In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”) it has not made and will not make an offer of shares to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of shares to the public in that Relevant Member State at any time:

      (a) to legal entities which are authorised or regulated to operate in the financial markets or, if not so authorised or regulated, whose corporate purpose is solely to invest in securities;

      (b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; or

      (c) in any other circumstances which do not require the publication by us of a prospectus pursuant to Article 3 of the Prospectus Directive.

      For the purposes of this provision, the expression an “offer of shares to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe

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the shares, as the same may be varied in that Member State by any measure implementing the Prospectus Directive in that Member State and the expression Prospectus Directive means Directive 2003/71/ EC and includes any relevant implementing measure in each Relevant Member State.

      The shares may not be offered or sold by means of any document other than to persons whose ordinary business is to buy or sell shares or debentures, whether as principal or agent, or in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32) of Hong Kong, and no advertisement, invitation or document relating to the shares may be issued, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571) of Hong Kong and any rules made thereunder.

      This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation or subscription or purchase, of the securities may not be circulated or distributed, nor may the securities be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than under circumstances in which such offer, sale or invitation does not constitute an offer or sale, or invitation for subscription or purchase, of the securities to the public in Singapore.

      The securities have not been and will not be registered under the Securities and Exchange Law of Japan (the Securities and Exchange Law) and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Securities and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

      The underwriters do not expect sales to discretionary accounts to exceed five percent of the total number of shares offered.

      We and BP estimate that their share of the total expenses of the offering, excluding underwriting discounts and commissions, will be approximately $                    .

      We and BP have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act of 1933.

      Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for us and BP, for which they received or will receive customary fees and expenses.

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VALIDITY OF THE SHARES

      The validity of our common stock offered by this prospectus will be passed upon for us by Sullivan & Cromwell LLP, New York, New York, and for the underwriters by Davis Polk & Wardwell.

EXPERTS

      The combined financial statements of Innovene Inc. at December 31, 2003 and 2004 and for each of the three years in the period ended December 31, 2004, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

      We have filed with the SEC a registration statement on Form S-1 under the Securities Act that registers the shares of our common stock to be sold in this offering. The registration statement, including the attached exhibits and schedules, contains additional relevant information about us and our capital stock. The rules and regulations of the SEC allow us to omit various information included in the registration statement from this document.

      In addition, upon completion of the offering, we will become subject to the reporting and information requirements of the Exchange Act and, as a result, will file periodic reports, proxy statements and other information with the SEC. You may read and copy this information at the public reference room of the SEC at 100 F Street, N.E., Washington, DC 20549. You may also obtain copies of this information by mail from the public reference room of the SEC, 100 F Street, N.E., Washington, DC 20549, at prescribed rates. You may obtain information on the operation of the public reference room by calling the SEC at 1 (800) SEC-0330.

      The SEC also maintains an Internet website at http://www.sec.gov that contains reports, proxy statements and other information about issuers like us who file electronically with the SEC.

      We intend to furnish our shareholders with annual reports containing audited financial statements and make available to our shareholders quarterly reports containing unaudited interim financial information for the first three quarters of each fiscal year.

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GLOSSARY

Term	Definition
Acrylonitrile-butadiene styrene (ABS)	ABS is a tough thermoplastic that has a variety of consumer appliance and automotive component uses. It is made from acrylonitrile, butadiene and styrene.
Acetonitrile	Acetonitrile is co-produced in the manufacture of acrylonitrile and is largely used in solvents.
Acrylic acid	Acrylic acid is produced from propylene and used in manufacturing absorbent polymers, coatings and adhesives/sealants.
Acrylonitrile	Acrylonitrile is a commodity used in a wide variety of consumer applications. It is used in the production of acrylic fiber, ABS and SAN. Acrylonitrile is manufactured from propylene, ammonia and air with the use of a catalyst.
Alkylation	Alkylation is a process for refining light products from the FCC to make high-octane gasoline.
Alpha olefins	See “Linear alpha olefins” and “Poly alpha olefins.”
Ammonia	Ammonia is used in the manufacture of acrylonitrile, although its largest end use is in the manufacture of fertilisers. It is made from nitrogen and hydrogen with the use of a catalyst.
Asphalt	Asphalt, a refinery product, is a liquid used for road surfacing and roofing.
Benzene	Benzene is a building block for styrene and is also used to make cumene and nylon. It is mainly produced from refinery processes or as a co-product of steam cracker operations.
Butadiene	Butadiene, a gas, is one of the co-products of the steam cracking process and is used primarily in the production of polymers, principally synthetic rubbers such as SBR, which is used to manufacture tires and other rubber products.
Co-monomer	Co-monomers are mainly used in combination with ethylene to make some types of polyethylene.
Cracker	See “Olefins cracker.”
Cumene	Cumene is produced from benzene and propylene and is used as a feedstock for producing phenol/acetone, which have large uses in the manufacture of plastics and resins.
Ethylene glycol (EG)	EG is an industrial chemical, primarily used in the manufacture of polyesters and antifreeze/coolants. It is produced from ethylene oxide.
Ethylene oxide (EO)	EO is mainly used to produce EG and industrial detergents. It is manufactured from ethylene and oxygen.
Ethanolamines	Ethanolamines are derivatives of EO used largely in industrial detergents and herbicides.
Ethylbenzene	Ethylbenzene is an intermediate made from benzene and ethylene and used to make styrene. Virtually all worldwide ethylbenzene production is consumed in the manufacture of styrene.

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Term	Definition
Ethylene	Ethylene is a flammable gas obtained in a process called steam cracking. Ethylene itself has no consumer applications, but is the basic feedstock for a large number of industrial uses, including the manufacture of polyethylene. Ethylene is a key building block for polyethylene, polystyrene, EO and other derivatives.
Ethylene dichloride	Ethylene dichloride is a liquid used as an intermediate to make polyvinyl chloride, which is used for water piping (outside/underground), sidings, as well as for sewers, drains, wastes and venting pipes and fittings. It is made from ethylene and chlorine.
Expandable polystyrene (EPS)	EPS is polystyrene that, when heated, forms a lightweight foam used for packaging and insulation purposes. Styrene is the main feedstock to manufacture EPS.
Fluidized catalytic cracker (FCC)	An FCC is a type of oil refining cracker that makes gasoline components with high octane levels and some co-produced lighter products.
Fractionator	A fractionator splits gas into its components ethane, propane, butane and other NGLs.
Gas	Gas includes methane, ethane, butane and propane.
Glycol ethers	Glycol ethers are used as solvents in paints, inks and cleaning fluids, and are derivatives of EO.
Hydrocracker (HC)	An HC is a type of oil refining cracker which makes refined products such as diesel and jet fuel, as well as some co-product quantities of LPGs.
High-density polyethylene (HDPE)	HDPE is a type of polyethylene and is a relatively tough thermoplastic. Its most common household use is container plastics. HDPE is also commonly used for molding, pipe and thin film applications.
Heating gas oil	Heating gas oil is a refinery product.
Hydrocarbons	Hydrocarbons is used to describe all compounds that consist of hydrogen and carbon. These include crude oil, natural gas, gas, olefins and their derivatives.
Hydrogen cyanide	Hydrogen cyanide is manufactured as a co-product of acrylonitrile. Hydrogen cyanide is an extremely hazardous gas used mainly to produce polymers, coatings and nylon, and for chemicals used in gold extraction.
Linear alpha olefins (LAOs)	LAOs are hydrocarbons in a straight chain formation which have physical characteristics and commercial uses that vary according to the length of the hydrocarbon chain. LAOs are co-monomers for certain types of polyethylene. They also have applications as surfactant intermediates, base oil for synthetic lubricants and drilling fluids. They are made from ethylene.
Low-density polyethylene (LDPE)	LDPE was the first type of polyethylene to be invented. Its most common household use is in plastic bags.
Linear low-density polyethylene (LLDPE)	LLDPE is a type of polyethylene and has basic properties similar to LDPE. LDPE and LLDPE are to a certain extent substitutable for each other. The most significant end use for LLDPE is film.

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Term	Definition
Liquified petroleum gas (LPG)	LPG is a mixture of gases, usually propane and butane, used as fuel in heating appliances and vehicles and also as a petrochemical feedstock.
Naphtha	Naphtha is a refinery product that is used as a gasoline component, but also serves as feedstock for petrochemical plants.
Natural gas liquids (NGL)	NGLs generally comprise a mixture of ethane, propane, butanes and smaller amounts of other lighter hydrocarbons.
Nitriles	Nitriles is used to describe acrylonitrile, its co-products and other products produced from ammonia feedstock.
Olefins	Olefins, including ethylene and propylene, are the key building blocks of the petrochemical industry and produce a large range of derivative products.
Olefins cracker	An olefins cracker breaks down naphtha or gas feedstocks into olefins, principally ethylene and propylene.
Organoleptic products	Organoleptic products, including caps and closures made from polyethylene, impart no taste or odor to the contents of the container.
Oxo-alcohols	Oxo-alcohols are a feedstock for intermediates which are used in many soft plastic products and solvent applications. They are largely produced from propylene feedstock.
Poly alpha olefins (PAOs)	PAOs are made by polymerising, or merging, several LAOs together and are mainly used as synthetic lubricants.
Propylene glycols (PGs)	PGs are an industrial chemical, mainly used to produce polyester, paints and coatings, airplane de-icers, antifreeze and industrial coolants. PG is made from propylene oxide.
Polyisobutylene (PIB)	PIB is a synthetic polymer available in a wide variety of viscosities for use in a broad range of industrial applications including lubricants, sealants, cling film, cables and adhesives.
Propylene oxide (PO)	PO is used in manufacture of polyurethane foams and to make propylene glycols (PG). PO is primarily made from propylene feedstock.
Polyethylene	Polyethylene (including HDPE, LDPE, and LLDPE) is the world’s most widely used thermoplastic, manufactured by aggregating many ethylene and co-monomer molecules in a process called polymerization. Polyethylene is used primarily to produce films for packaging, agricultural applications, molded products, pipes and coatings.
Polymer	A polymer is a chemical compound usually made up of a large number of identical components linked together into long molecular chains.
Polypropylene	Polypropylene is the world’s second most widely used thermoplastic after polyethylene. It is manufactured by the polymerization of propylene. It is used mainly for molding, filaments, fibers and films. Polypropylene is the most significant thermoplastic material used in molded containers and automotive applications.
Polystyrene	General purpose, or “crystal,” polystyrene and high impact polystyrene are hard and brittle materials which are used mainly for packaging, appliance and electrical housings and insulation. Both forms are also used for plastic molding applications. Styrene is the main feedstock used to manufacture polystyrene.

135

Term	Definition
Propylene	Propylene is a flammable gas which is largely derived either as a co-product of the refinery FCC process used to make gasoline or as a co-product of the steam cracking process used to make ethylene. Propylene has virtually no independent end use, but is an important input for a significant number of industrial products, and is the main feedstock used to make polypropylene and acrylonitrile.
Pygas	Pygas is a by-product of olefins production from steam crackers and is used by refineries as a liquid gasoline blending component.
Styrene-acrylonitrile (SAN)	SAN is made from styrene and acrylonitrile, used in variety of applications, including housewares and appliances.
Styrene-butadiene latex (SBL)	SBL is a polymer derivative made from styrene and butadiene, used mainly in paper coatings and carpet backing applications.
Styrene-butadiene rubber (SBR)	SBR is a polymer derivative made from styrene and butadiene, used mainly in manufacture of tires and other rubber products.
Solvents	Solvents are used to dissolve solids and keep them in liquid form.
Styrene	Styrene, a hydrocarbon which under normal conditions is a flammable liquid, is produced from ethylene and benzene, via ethylbenzene. The largest use of styrene is in the production of polystyrene, although it is also used in many other derivatives such as ABS, SBR, SBL and SAN.
Synthetic ethanol	Synthetic ethanol is a solvent used in personal care products, inks, household chemicals and industrial applications as well as in the manufacture of other chemical products.
Thermoplastic	A thermoplastic is a plastic which softens when heated and hardens again when cooled. Thermoplastics include polyethylene, polypropylene and polystyrene.

136

INNOVENE Inc.

Index to Combined Financial Statements

	Page
Combined Financial Statements as of and for the years ended December 31, 2002, 2003 and 2004 and the six months ended June 30, 2004 and 2005
Report of Independent Registered Public Accounting Firm		F-2
Combined Balance Sheets as of December 31, 2003 and 2004, and June 30, 2005 (unaudited)		F-3
Combined Statements of Operations for the years ended December 31, 2002, 2003 and 2004 and the six months ended June 30, 2004 and 2005 (unaudited)		F-4
Combined Statements of Owner’s Equity and Comprehensive Income for the years ended December 31, 2002, 2003 and 2004 and the six months ended June 30, 2005 (unaudited)		F-5
Combined Statements of Cash Flows for the years ended December 31, 2002, 2003 and 2004 and the six months ended June 30, 2004 and 2005 (unaudited)		F-6
Notes to Combined Financial Statements		F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Owner

Innovene Inc.

      We have audited the accompanying combined balance sheets of Innovene Inc. as of December 31, 2004 and 2003, and the related combined statements of operations, owner’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed at Item 16(b). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of Innovene Inc. at December 31, 2004 and 2003, and the combined results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

Ernst & Young LLP

London, United Kingdom

September 9, 2005

(except for Note (1) as to which the date is                     , 2005)

The foregoing report is in the form that will be signed upon the completion of certain transactions as described in Note (1) to the combined financial statements.

/s/ Ernst & Young LLP

London, United Kingdom

September 9, 2005

F-2

INNOVENE Inc.

Combined Balance Sheets

			As of December 31,				As of
							June 30,
			2003		2004		2005
							(unaudited)
			($ in millions)
ASSETS
Current assets
	Cash			24		45		—
	Trade accounts receivable, net of allowance for doubtful accounts of $18 million, $23 million, and $23 million, at December 31, 2003 and 2004 and June 30, 2005, respectively			1,619		1,940		1,923
	Receivables from affiliates			—		—		576
	Inventories (Note 6)			1,393		1,746		2,030
	Other current assets (Note 7)			484		667		600
		Total current assets		3,520		4,398		5,129
Property, plant, and equipment, net (Note 8)				7,050		7,136		6,737
Investment in and advances to affiliates				137		150		145
Goodwill and other intangible assets (Note 11)				259		261		258
Deferred tax assets (Note 18)				167		106		61
Prepayments and other assets				145		148		133
Assets of discontinued operations (Note 10)				178		15		—
		Total assets		11,456		12,214		12,463
LIABILITIES, MINORITY INTEREST AND OWNER’S EQUITY
Current liabilities
	Trade accounts payable			1,103		1,168		718
	Payables to affiliates			—		—		1,075
	Accrued liabilities			725		643		692
	Other current liabilities (Note 12)			196		352		323
	Due to parent (Note 13)			—		—		1,700
	Deferred income taxes (Note 18)			61		47		—
		Total current liabilities		2,085		2,210		4,508
Long term debt (Note 13)				1,585		1,729		—
Other non-current liabilities (Note 14)				481		553		347
Deferred income taxes (Note 18)				746		699		317
Liabilities of discontinued operations (Note 10)				40		10		—
		Total liabilities		4,937		5,201		5,172
Minority interest				1,242		—		—
Owner’s equity
	Parent net investment			4,095		5,548		6,174
	Accumulated other comprehensive income, net of tax			1,182		1,465		1,117
		Total owner’s equity		5,277		7,013		7,291
		Total liabilities, minority interests and owner’s equity		11,456		12,214		12,463

See accompanying notes to combined financial statements.

F-3

INNOVENE Inc.

Combined Statements of Operations

											For the six
											months ended
		For the year ended December 31,									June 30,
		2002			2003			2004			2004			2005
											(unaudited)
		($ in millions)
Revenues			11,776			13,422			17,937			7,791			11,131
Cost of sales			(10,775	)		(12,586	)		(16,765	)		(7,253	)		(9,876	)
	Gross margin		1,001			836			1,172			538			1,255
Selling, general and administrative expenses			(734	)		(616	)		(630	)		(341	)		(341	)
Research and development expenses			(120	)		(115	)		(137	)		(64	)		(51	)
Restructuring and asset impairment charges (Note 15)			(93	)		(72	)		(345	)		(5	)		(21	)
	Operating profit		54			33			60			128			842
Equity income (loss) from investments in affiliates			(2	)		9			8			5			4
Interest expense			(35	)		(44	)		(49	)		(25	)		(25	)
Other income (expense), net (Note 5)			(65	)		(123	)		(24	)		27			(42	)
	Income (loss) from continuing operations before income taxes		(48	)		(125	)		(5	)		135			779
	Provision for income taxes for continuing operations (Note 18)		(118	)		(90	)		(128	)		(86	)		(233	)
	Net income (loss) from continuing operations		(166	)		(215	)		(133	)		49			546
	Loss from discontinued operations, net of income tax expense (benefit) of $0, $0, $(52) million, $0, and $0 (Notes 10 and 18)		(29	)		(25	)		(128	)		(11	)		(3	)
	Net income (loss)		(195	)		(240	)		(261	)		38			543

See accompanying notes to combined financial statements.

F-4

INNOVENE Inc.

Combined Statements of Owner’s Equity and Comprehensive Income

					Accumulated other
		Parent net			comprehensive			Owner’s equity			Comprehensive
		investment			income			total			income
		($ in millions)
Balance at December 31, 2001			4,461			(5	)(1)		4,456			—
	Net loss		(195	)		—			(195	)		(195	)
	Foreign currency translation adjustment		—			610			610			610
	Minimum pension liability, net of tax $9 million		—			(15	)		(15	)		(15	)
	Tax effect of transaction with affiliate		148			—			148			—
	Transfers from parent, net		56			—			56			—
Balance at December 31, 2002			4,470			590			5,060			400
	Net loss		(240	)		—			(240	)		(240	)
	Foreign currency translation adjustment		—			602			602			602
	Minimum pension liability, net of tax $8 million		—			(10	)		(10	)		(10	)
	Transfers to parent, net		(135	)		—			(135	)		—
Balance at December 31, 2003			4,095			1,182			5,277			352
	Net loss		(261	)		—			(261	)		(261	)
	Foreign currency translation adjustment		—			302			302			302
	Minimum pension liability, net of tax $14 million		—			(19	)		(19	)		(19	)
	Transfers from parent, net		1,714			—			1,714			—
Balance at December 31, 2004			5,548			1,465			7,013			22
	Net income		543			—			543			543
	Foreign currency translation adjustment		—			(371	)		(371	)		(371	)
	Minimum pension liability, net of tax $10 million		—			23			23			23
	Net transfers upon legal separation (Note 4)		589			—			589			—
	Transfers to parent, net		(506	)		—			(506	)		—
Balance at June 30, 2005 (unaudited)			6,174			1,117			7,291			195

Note:

(1) Balance solely relates to minimum pension liabilities, net of tax of $3 million.

See accompanying notes to combined financial statements.

F-5

INNOVENE Inc.

Combined Statements of Cash Flows

													For the six
				For the year ended									months ended
				December 31,									June 30,
				2002			2003			2004			2004			2005
													(unaudited)
				($ in millions)
Cash flows from operating activities:
	Net income (loss) from continuing operations				(166	)		(215	)		(133	)		49			546
	Adjustments to reconcile net profit/(loss) to net cash provided from (used in) operating activities:
		Depreciation and amortization			423			517			545			244			284
		Asset impairments			32			36			280			—			—
		Restructuring charges, net of cash paid			(10	)		(53	)		9			(17	)		(2	)
		Deferred income taxes			78			49			(24	)		44			(5	)
		(Gain) loss from foreign exchange revaluation			112			155			123			11			(19	)
		Loss on extinguishment of debt			—			—			—			—			45
		(Gain) loss on disposal of assets			(25	)		7			—			—			—
		Decrease (Increase) in the fair value of the BP Solvay Ventures liabilities			128			168			105			(10	)		—
		Other			16			9			23			(4	)		(4	)
		Changes in assets and liabilities, net of acquisitions:			(411	)		22			(545	)		196			(81	)
Net cash provided by operating activities of continuing operations					177			695			383			513			764
Net cash used in operating activities of discontinued operations					(21	)		(17	)		(10	)		(6	)		(18	)
Net cash provided by operating activities					156			678			373			507			746
Cash flows from investing activities:
	Capital expenditures				(614	)		(556	)		(567	)		(218	)		(250	)
	Proceeds from the sale of assets				30			—			—			—			—
	Acquisitions of businesses				5			—			—			—			—
	Dividends received				—			2			2			—			—
	Investments in and advances to affiliates				—			(7	)		—			—			—
Net cash used in investing activities of continuing operations					(579	)		(561	)		(565	)		(218	)		(250	)
Net cash used in investing activities of discontinued operations					(3	)		(2	)		(3	)		—			20
Net cash used in investing activities					(582	)		(563	)		(568	)		(218	)		(230	)
Cash flows from financing activities:
	Acquisition of minority interest				—			—			(1,538	)		—			—
	Proceeds from subsidiary capital calls				100			21			40			37			—
	Repayments of long term debt				—			(7	)		—			—			(1,755	)
	Proceeds from issuance of long term debt				290			—			—			—			—
	Proceeds from issuance of short term debt				—			—			—			—			1,700
	Transfers (to) from parent, net				32			(154	)		1,701			(297	)		(504	)
Net cash provided by (used in) financing activities of continuing operations					422			(140	)		203			(260	)		(559	)
Net cash provided by (used in) financing activities of discontinued operations					24			19			13			6			(2	)
Net cash provided by (used in) financing activities					446			(121	)		216			(254	)		(561	)
			Net increase (decrease) in cash and cash equivalents		20			(6	)		21			35			(45	)
Cash and cash equivalents at beginning of period					10			30			24			24			45
Cash and cash equivalents at end of period					30			24			45			59			—
Supplemental disclosure:
	Income taxes paid				40			41			152			42			239
	Interest paid				35			44			49			25			25

See accompanying notes to combined financial statements.

F-6

INNOVENE Inc.

Combined Statements of Cash Flows — (Continued)

											For the six
		For the year ended									months ended
		December 31,									June 30,
		2002			2003			2004			2004			2005
											(unaudited)
		($ in millions)
Changes in assets and liabilities, net of acquisitions:
	Trade accounts receivable		(298	)		(364	)		(324	)		68			17
	Receivables from affiliates		—			—			—			—			(576	)
	Inventories		(197	)		(157	)		(346	)		(88	)		(291	)
	Other current assets		79			(135	)		(183	)		63			68
	Prepayments and other assets		(15	)		(25	)		(3	)		21			15
	Trade accounts payable		106			494			65			247			(450	)
	Payables to affiliates		—			—			—			—			1,075
	Accrued liabilities		49			115			(82	)		(141	)		49
	Other current liabilities		(3	)		73			293			5			(31	)
	Other non-current liabilities		(132	)		21			35			21			43
Changes in assets and liabilities, net of acquisitions			(411	)		22			(545	)		196			(81	)

See accompanying notes to combined financial statements.

F-7

INNOVENE Inc.

Notes to Combined Financial Statements

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

(1) Background

      Innovene Inc. (“Innovene” or the “Company”) is currently an indirect wholly-owned subsidiary of BP p.l.c. (“BP”). The Company anticipates completing an initial public offering before December 31, 2005. Prior to the offering, BP will transfer to Innovene certain assets, liabilities and the associated operations that were formerly part of BP’s Petrochemicals, Refining and Marketing, and Gas, Power and Renewables segments. Specifically, the Company combines (a) all of BP’s petrochemical operating units for olefins, polymers and other derivatives (collectively “O&D”), (b) two integrated refinery plants in Grangemouth, Scotland, and Lavéra, France, (c) a gas fractionator located in Hobbs, New Mexico and certain related pipelines, and (d) existing O&D strategic joint venture investments (collectively, the Company’s “Manufacturing Interests”). The most important products manufactured from the Company’s Manufacturing Interests are ethylene, propylene, polyethylene (including high-density polyethylene), polypropylene, styrene, polystyrene, acrylonitrile, alpha olefins, solvents, transport fuels, particularly diesel fuel and gasoline, naphtha, and heating and fuel oils. Innovene will be a worldwide manufacturer and marketer of these products, with major manufacturing sites at Grangemouth in Scotland, Cologne in Germany, Lavéra in France and Chocolate Bayou and Battleground in the United States.

      In accordance with the Amended and Restated Master Reorganization Agreement, BP transferred to separate legal entities effective April 1, 2005, substantially all of the assets and liabilities, including fixed assets, inventory, and non-monetary working capital related to the Company’s Manufacturing Interests (the “Separation”). Innovene will conduct the ongoing operations relating to the Manufacturing Interests transferred to it as part of the Separation. Prior to the offering, the separate legal entities will be transferred to Innovene Inc.

      Until the transfers occur, Innovene has no material assets, liabilities or operations. These combined financial statements describe Innovene and its financial condition and operations as if it held the operations and separate entities that will be transferred to it for all historical periods presented.

      Innovene and BP have entered into a series of agreements which provide for the transfer of substantially all of the assets and liabilities within the scope of our current and future business activities from BP to the Company, subject to the retention by BP of certain historic liabilities. These agreements include a series of Local Transfer Agreements, the Intellectual Property and Information Technology Separation Agreement, the Master Reorganization Agreement and the tax sharing agreements (together, the “Reorganization Agreements”). The agreements also establish arm’s length commercial arrangements between the Company and BP and require BP to provide the Company with transitional support for a limited period of one to three years, (the “Commercial Interface Agreements”). For purposes of these agreements, the legal separation is deemed to have occurred on April 1, 2005, whereas, except for the tax sharing agreements, the commercial arrangements are effective from January 1, 2005.

(2) Basis of Presentation

      The combined financial statements have been prepared using the historical cost basis in the assets and liabilities and historical results of operations related to the Company’s Manufacturing Interests, and may not be indicative of the actual results of operations and financial position of the Company had it operated as a separate entity.

      Because direct ownership relationships did not exist among the various Manufacturing Interests, BP’s net investment in the Company is presented as “Parent net investment”. The accompanying combined balance sheets do not include certain BP assets and liabilities that are not specifically identifiable to the Company’s Manufacturing Interests.

F-8

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      BP manages its cash, accounts payable and certain related matters on a centralized basis for the entire BP group, which in the three years and six months ended June 30, 2005 included the Company. BP’s financial systems are not designed to track intercompany working capital balances, accounts payable, cash receipts, and payments separately for each production unit. Accordingly, in preparing the combined financial statements, it was not practicable to determine certain assets and liabilities associated with the Company. Assets and liabilities not specifically identifiable to the Company include:

•  Cash and cash equivalent balances that are recorded in the Parent net investment account. The cash that is presented on the balance sheet is cash belonging to certain consolidated joint ventures.

•  Accounts payable related to trade purchases that are made centrally by BP, but nonetheless related to the Company that are reflected in the Parent net investment account.

•  Accrued liabilities related to corporate allocations that are reflected in the Parent net investment account.

•  Intercompany working capital balances between BP and its affiliates (unless directly traceable to a third-party relationship), which are not settled on a current basis and are not tracked separately for each production unit. To the extent that such balances relate to the Company, they are reflected in the Parent net investment account.

•  Hedging positions through which derivative and other financial contracts are used to offset exposures to interest rates, commodity prices or foreign exchange rates, unless individual instruments are specifically attributable to an underlying Innovene asset, liability or anticipated series of cash flows (see Note 21).

•  Third party financing and related balances, such as debt and capital leases that are managed centrally by BP and which are not secured by Company assets.

•  Until BP’s shareholding in the Company falls below the limits set out in the Master Reorganization Agreement of 80% in the U.S. and 50% elsewhere, the Company’s employees generally will continue to participate in BP’s group-wide pension and other post employment plans. As long as this is the case, assets and obligations related to these plans will be owned directly by BP.

•  Assets and obligations related to the Company’s participation in BP’s stock option schemes, and, in particular, the BP ESOP trusts are not separately allocable to employees or employee costs.

      The combined statements of operations include all revenues and costs attributable to the Manufacturing Interests including an allocation of the cost of shared utilities, overhead and administrative expenses related to general management, information technology, human resources and other services provided to the Company by BP. As further described in Note 4, these allocations were made based on such criteria as personnel or business volume. All of the allocations and estimates in the combined statements of operations are based on assumptions that management believes are reasonable under the circumstances. However, these allocations and estimates are not necessarily indicative of the costs that the Company would have incurred if it had operated on a standalone basis or as an entity independent of BP.

(3) Summary of Significant Accounting Policies

Basis of Combination

      The accompanying combined financial statements are presented on the basis of accounting principles generally accepted in the United States of America. Within the Company’s group, all intercompany accounts and transactions have been eliminated. Companies and joint ventures in which Innovene has or had a significant influence, but not a controlling interest, are carried on the equity basis and are included in “Investment in and advances to affiliates”. The Company’s share of earnings or losses in these investments is included in “Equity

F-9

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

income/ (loss) from investments in affiliates”. As a result of Innovene’s adoption of FASB Interpretation No. 46, Consolidation of Variable Interest Entities, all variable interest entities in which the Company is determined to be the primary beneficiary are consolidated in the combined financial statements.

Use of Estimates

      The preparation of the combined financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions affecting the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates presented and the reported amounts of revenues and expenses during the periods presented. Significant estimates include: the recognition of an impairment, if any, relating to property, plant, and equipment, intangibles, and goodwill; litigation-related obligations; valuation allowances for receivables, inventories, and deferred income tax assets; environmental liabilities; allocation of the purchase price for businesses acquired; recoverability of long-lived assets; restructuring and plant closing costs; revaluation of derivative instruments; and assets and obligations related to employee benefits, such as amounts reported for pensions, plan assets, and post-employment benefits. Actual results could differ from those estimates.

Inventories

      Inventories are valued at the lower of cost or market value.

      Elements of cost in inventories include raw materials, direct labor and manufacturing overhead. Inventory consists of the balance on hand of raw materials, work in progress, and finished goods held for sale. Stores inventory include catalysts and consumable materials used in the production process.

      The majority of the Company’s inventories in the United States are valued at cost using the “last in, first out” (“LIFO”) method. Inventories valued using the LIFO method comprised approximately 10% and 7% of total inventories at December 31, 2003 and 2004, respectively.

      The balance of the Company’s inventories are valued using the “first in, first out” method. The Company’s stores inventories are mainly valued using the average cost method or, if lower, at their market value.

      The Company uses the dollar value method for computing its LIFO inventory valuation in the United States. This method, by its nature, involves an annual calculation. In preparing quarterly balance sheets, the Company spreads forecast movements in the LIFO layers across the year based on movements in inventory during the year.

Property, Plant and Equipment

      Property, plant and equipment are stated at cost and depreciated over their estimated useful lives using the straight line method. The average of the estimated useful lives of the Company’s refineries and petrochemical manufacturing plants is 20 years.

      Expenditures incurred in connection with major maintenance operations, refits or repairs are capitalized only where they enhance the performance of the asset being maintained, refitted or repaired above its originally assessed standard of performance or replaces an asset (or part of an asset) which was separately depreciated and then written off or restore the economic benefits of an asset that has been fully depreciated. Such expenditures are amortized over their respective estimated useful lives. All other maintenance costs are expensed as incurred.

      Interest costs incurred as part of major construction projects are capitalized. Net annual interest expense capitalized as part of property, plant and equipment was $2 million, $9 million, and $10 million during the years ended December 31, 2002, 2003 and 2004, respectively.

F-10

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      The cost and accumulated depreciation are removed from the respective accounts upon retirement or sale of property, plant and equipment. Upon retirement, any resulting loss is included in costs of goods sold in the combined statement of operations and upon sale, the resulting gain or loss is included in other income (expense) in the combined statement of operations.

Long-Lived Assets

      The Company reviews the carrying value of its long-lived assets, including property, plant and equipment and definite-lived intangible assets whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the total of the undiscounted future cash flows is less than the carrying amount of the asset or asset group, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the asset or asset group. The Company recorded impairments on long-lived assets of $32 million, $36 million and $280 million for the years ended December 31, 2002, 2003 and 2004, respectively. In addition, an impairment of $148 million was reflected as discontinued operations in 2004.

      The Company complies with FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. An impairment loss on a long-lived asset is recognized if the asset’s carrying amount is not recoverable and exceeds its fair value. Long-lived assets to be sold are separately classified as held for sale when the Company commits to a plan for sale or disposal.

Goodwill and Other Intangible Assets

      Goodwill represents the excess of the cost of an acquired entity or business over the fair value of the net assets acquired. Goodwill impairment is considered at least annually or when events or circumstances indicate the fair value of a reporting unit may be less than its carrying value. The Company recorded no goodwill impairment charges for the years ended December 31, 2002, 2003 and 2004.

      Upon adoption of FASB Statement No. 142, Goodwill and Other Intangible Assets, on January 1, 2002, the Company ceased to amortize goodwill. Intangible assets with definite useful lives (other than goodwill) are amortized over their estimated useful lives up to a maximum period of 20 years. The Company has no intangible assets with indefinite useful lives other than goodwill.

      Capitalized costs associated with computer software developed for internal use are amortized on a straight-line basis over 4 to 7 years.

Investments in Affiliates

      Investments in non-consolidated companies over which the Company has significant influence are accounted for under the equity method. The Company assesses any decline in the value of individual investments to determine whether such decline is other than temporary and thus whether the relevant investment is impaired. This assessment is made by considering available evidence, including changes in general market conditions, specific industry and individual Company data, the length of time and the extent to which the market value has been less than cost, the financial condition and near term prospects of the individual entity, and the Company’s intent and ability to hold the investment. Investments in Affiliates is primarily comprised of Innovene’s investments in five manufacturing joint ventures in Lavéra, France.

Financial Instruments

      The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. The carrying values of all current assets and current liabilities approximate their fair value because of their short-term nature. The carrying value of long-term debt

F-11

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

approximates its fair value based on management’s estimates for similar debt, giving consideration to rating, interest rates, maturity and other significant characteristics.

Derivative Instruments and Hedging Activities

      The Company accounts for derivatives and hedging activities in accordance with FASB Statement No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended, which requires that all derivative instruments be recorded on the balance sheet at their respective fair values. If the derivative is designated as a fair-value hedge, the changes in the fair value of the derivative and the hedged items are recognized in earnings. If the derivative is designated as a cash flow hedge, changes in the fair value of the derivative are recorded in other comprehensive income and will be recognized in the income statement when the hedged item affects earnings.

      The purpose for which a derivative contract is used is identified at inception. To qualify as a derivative for hedging, the contract must be in accordance with established guidelines that ensure that it is effective in achieving its objective. All contracts not identified at inception as being for the purpose of hedging are designated as being held for trading purposes and accounted for using fair value method.

Employee Benefit Plans

      For pension and other post-employment benefit plans in which Innovene employees participate, costs are determined in accordance with FASB Statement No. 87, Employers’ Accounting for Pensions, FASB Statement No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, and FASB Statement No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions.

      Post-retirement benefit costs consist of service cost, interest cost on accrued obligations and the expected return on assets (calculated using a smoothed market value of assets). Any difference between actual and expected returns on assets during a year and actuarial gains and losses on liabilities together with any prior service costs are charged (or credited) to income over the average remaining service lives of employees which is estimated to be 10 years. No amortization has been applied for plans outside of the U.S. in the historic results presented.

      For BP plans in which BP employees (including those of the predecessor businesses of Innovene) participate (Group plans), BP determined pensions and other post-employment benefit costs on a consolidated basis. Separate Company information is not readily available. The benefit cost components shown in the combined statements of operations reflect an allocation of the costs (including the costs for retirees and former employees of the predecessor businesses) for these BP Group Plans. The allocation was based on the predecessor businesses of Innovene’s active population for each period presented.

      For pension and other post-employment plans in which only Innovene employees participate, disclosures are provided in accordance with FASB Statement No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits.

Commitments and Contingencies

      Liabilities for loss contingencies, including environmental remediation costs not within the scope of FASB Statement No. 143, Accounting for Asset Retirement Obligations, arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.

F-12

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

Environmental Expenditures

      Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and that do not impact future earnings are expensed. Liabilities for environmental costs are recognized when environmental assessments or clean-ups are probable and the associated costs can be reasonably estimated. Generally, the timing of these provisions coincides with the commitment to a formal plan of action or, if earlier, the divestment or closure of the relevant sites. The amount recognized reflects management’s best estimate of the expenditures expected to be required. Where a liability is not to be settled for a number of years, the amount recognized is the estimated future expenditure on an undiscounted basis.

Revenue Recognition

      Revenue is recognized when risk and title to the product transfers to the customer, collectibility is reasonably assured and the price is fixed or determinable. Revenue is typically recognized at the time of shipment or delivery of a product, depending on the contractual terms. Revenue is recognized net of discounts and other price adjustments.

      Historically, the Company’s Refining operating segment was integrated within BP’s Refining & Marketing (“R&M”) reporting entities. No revenue was recognized for refining in the R&M business, since there were no direct sales to third parties. For the purposes of the combined financial statements, revenue presented was determined based on production throughput, valued at an average sales price per product grade in the applicable periods. With effect from January 1, 2005, revenues of the Company’s Refining segment have been recognized in a manner consistent with the Company’s revenue recognition policy described above.

Cost of Sales

      The Company classifies the costs of manufacturing and distributing its products as cost of sales. Manufacturing costs include raw materials and variable and fixed manufacturing costs associated with production. Fixed manufacturing costs include, among other things, plant site operating costs and overhead, production planning, depreciation and amortization, repairs and maintenance, plant site purchasing costs, and engineering and technical support costs.

Research and Development Costs

      The Company conducts a broad range of research and development activities aimed at improving existing products and manufacturing processes and developing new products and processes. Research and development costs are expensed as incurred.

Trade Accounts Receivable

      Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts reflect management’s best estimate of the amount of probable losses with respect to the Company’s accounts receivable. The Company determines the allowance based on a monthly review of the collectibility of each overdue balance. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure to its customers.

F-13

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

Lease Transactions

      The Company leases certain machinery, equipment and facilities under long-term lease agreements with third parties. The Company reviews the terms of each lease at inception of the lease in order to determine whether it should be treated as an operating or a capital lease under FASB Statement No. 13, Accounting for Leases, and its interpretations. Operating leases are expensed on a straight line basis over the term of the lease.

Stock Based Compensation

      Certain of the Company’s employees participate in BP’s long term incentive plans. Under the plans, employees received various stock-based compensation awards, including stock options, restricted stock, stock opportunity grants and performance units, some of which have yet to be exercised. The Company currently accounts for stock-based compensation related to participants in BP’s plans using the intrinsic value method prescribed by Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, whereby the options are granted at market price, and therefore no compensation costs are recognized. Compensation cost for stock options, if any, would be measured as the excess of the quoted market price at the grant date of the Company’s stock over the amount an employee must pay to acquire the stock. FASB Statement No. 123, Accounting for Stock-Based Compensation, and FASB Statement No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure, an amendment of FASB Statement No. 123, established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. As permitted by existing accounting standards, the Company has elected to continue to apply the intrinsic value method of accounting described above, and has adopted only the disclosure requirements of FASB Statement No. 123, as amended. Had compensation costs attributable to awards granted to employees of the Company been determined using the fair value accounting method, pro forma net loss would have been as follows:

	For the year ended
	December 31,
	2002			2003			2004
	($ in millions)
Net loss, as reported		(195	)		(240	)		(261	)
Deduct: Additional stock-based employee compensation expense under the fair value based method for all awards, net of tax		(7	)		(7	)		(7	)
Net loss, pro forma		(202	)		(247	)		(268	)

      The fair value of BP’s stock-based awards attributed to employees of the Company was estimated using the following weighted average assumptions for each of the years ended December 31, 2002, 2003 and 2004:

	For the year ended
	December 31,
	2002			2003			2004
Risk-free interest rate		4.00	%		3.50	%		4.00	%
Expected life (in years)		1 to 5			1 to 5			1 to 5
Expected volatility		26.00	%		30.00	%		22.00	%
Dividend yield		3.75	%		4.00	%		3.75	%

      Using the Black-Scholes pricing model, the weighted-average fair value of an option granted in 2002, 2003, and 2004, was $1.64, $1.44, and $1.40 respectively.

F-14

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

Foreign Currency Translation

      The accounts of the Company’s subsidiaries outside of the United States generally consider local currency to be their functional currency. Foreign currency transactions are recorded in the functional currency at the relevant exchange rates on the date of the transaction. Foreign currency assets and liabilities are translated into the functional currency at relevant exchange rates at the balance sheet date. Exchange differences are included in operating profit.

      Assets and liabilities are translated from the respective functional currency into U.S. dollars using exchange rates at the relevant balance sheet date. Revenues, expenses and cash flows are translated from the functional currency into U.S. dollars using average exchange rates for the reporting period. Exchange adjustments arising from the translation of the accounts from the respective functional currency into U.S. dollars are recorded as a component of owner’s equity.

Income Taxes

      The results of the Company have been included in the consolidated income tax assessments of BP for the periods presented. In the periods presented prior to  April 1, 2005, there was no formal tax sharing agreement between the Company and BP. Tax losses and credits generated by one member of the BP group that were utilized by another BP group member generally were compensated by the utilizing member. In preparing the combined financial statements the provision for income taxes has been calculated as if Innovene had been a standalone entity and filed separate returns during the periods presented. In light of the complexities and numerous assumptions inherent in preparing tax returns involving interactions between the U.S. tax system and the relevant non-U.S. tax systems including foreign tax credit computations, allocation and apportionment (including complying with national transfer pricing rules) of various expenses, such as consolidated interest expense, stewardship, research and development, etc., the provision for income taxes has been determined based on the assumption that such expenses would give rise to tax relief where incurred.

      The Company accounts for income taxes in accordance with the asset and liability method prescribed by FASB Statement No. 109, Accounting for Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period in which the rates have changed.

      BP manages its tax position for the benefit of its entire portfolio of businesses, and its tax strategies are not necessarily reflective of the tax strategies that Innovene would have followed or will follow as a standalone entity. Losses generated by the Company’s businesses historically were available to, and were often utilized by BP in its tax strategies with respect to entities or operations not forming part of the Company’s businesses. Due to difficulties inherent in separating the Company’s results from BP’s consolidated results during periods pre-dating the periods presented, any deferred tax assets in respect of operating loss carryforwards and tax credits have been fully offset by valuation allowances. This treatment also reflects the Company’s inability to quantify the amounts of these deferred tax assets, although the existence of these assets is acknowledged but the assets are not susceptible to accurate estimation. In the periods presented, current tax benefits are recognized to the extent of any deferred tax expense and increase in deferred tax liabilities recognized in the same period. Existing deferred tax liability balances are not considered in the evaluation of the ability to recognize current tax benefits and the associated deferred tax assets due to the inability to estimate the amount of deferred tax assets existing at the beginning of the periods presented which could partially or fully offset the existing deferred tax liabilities. Where loss carryforwards generated by one of the Company’s businesses were available to offset income from the same

F-15

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

business or another of the Company’s businesses within a given jurisdiction during the periods presented, the Company has reflected such loss carryforwards in the period they arose and has assessed its ability to realize these deferred tax assets based on the available evidence.

      Income taxes are deemed to have been paid on behalf of the Company by BP and are included in the parent net investment line of the combined balance sheets. The Company will be required to file separate United States federal income tax returns only after the sale of greater than 20% of the securities held by BP. The Company may be included in consolidated/ combined returns with BP for other tax jurisdictions, such as states, where consolidated/ combined ownership thresholds are different than the U.S. federal consolidated ownership threshold.

      The Company and BP have entered into tax sharing agreements effective April 1, 2005, that will generally govern BP’s and the Company’s respective rights, responsibilities and obligations for taxes after the registration of Innovene’s shares. With respect to all taxes for any tax period ending on or before April 1, 2005, BP generally will retain responsibility for any federal, foreign, and certain state taxes due and will benefit from tax refunds available. For any tax years subsequent to that date, the Company will be responsible for federal, foreign, and state taxes due and will benefit from tax refunds available. Following April 1, 2005, the Company will file tax returns, pay taxes due and receive the benefits from losses generated in foreign jurisdictions in which it operates. For the U.S., dependent on BP’s ownership share of the Company, the Company will either file its own U.S. tax return or the Company will pay to BP its allocable share as if the Company were a standalone taxpayer pursuant to the terms of the tax sharing agreements, for tax on income generated and BP will retain the benefits of tax losses, and will pay the Company for the benefits BP obtains from such tax losses, as long as the Company is part of any BP consolidated tax computations.

      Effective April 1, 2005, the Company received its assets from BP in a taxable asset transaction; accordingly, the Company will obtain a depreciable basis equal to the fair market value of the assets received from BP. The majority of non-U.S. asset transfers were taxable such that the depreciable assets are recorded at fair market value for tax purposes. Accordingly, the existing deferred tax asset and liability balances were reversed through Parent Net Investment and a deferred tax asset recorded, with an offsetting entry to equity, to the extent that the tax depreciable basis exceeded the depreciable net book value. The net effect of these transactions was to increase Parent Net Investment by $483 million.

      While BP’s US affiliates continue to own at least 80 percent of the Company, BP will include the Company in its consolidated US Federal tax return and, pursuant to the terms of the US Master Tax Agreement, the Company will not be entitled to claim the benefits of the tax depreciation in excess of the historical BP US group tax basis in the depreciable assets.

Earnings per share

      Historical earnings per share are not presented since Innovene common stock was not part of the capital structure of BP for the periods presented. Innovene will present basic and diluted earnings per share in the first report it issues after the effective date of the initial public offering.

Adoption of New Accounting Standards

      In 2002, the FASB issued FASB Statement No. 146, Accounting for Costs Associated with Exit or Disposal Activities. This standard requires companies to recognize costs associated with exit or disposal activities when they are incurred, rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, plant closing, or other exit or disposal activity. Statement 146 is required to be applied

F-16

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

prospectively to exit or disposal activities initiated after December 31, 2002, with earlier application encouraged. The Company adopted Statement 146 as of January 1, 2003. The adoption of Statement 146 did not have a significant impact on the Company’s financial position or results of operations.

      In November 2002, the FASB issued FASB Interpretation No. 45 Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45). FIN 45 modifies existing disclosure requirements for most guarantees and requires at the time the Company issues a guarantee, the Company must recognize an initial liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and measurement provisions of FIN 45 apply on a prospective basis to guarantees issued or modified after December 31, 2002. The adoption of FIN 45 did not have a significant effect on the Company’s financial position or results of operations.

      In June 2001, the FASB issued FASB Statement No. 143, Accounting for Asset Retirement Obligations, which applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, or the normal operation of the asset. Statement 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. Such estimates are generally determined based upon estimated future cash flows discounted using a credit-adjusted risk-free interest rate. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, the Company will recognize a gain or loss on settlement. The adoption of Statement 143 did not have a significant impact on the Company’s financial position or results of operations.

      In April 2003, the FASB issued FASB Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, which amends and clarifies the financial accounting and reporting of derivative instruments and hedging activities under Statement 133. Statement 149 applies to contracts entered into or modified after June 30, 2003, and hedging relationships designated after June 30, 2003. The adoption of Statement 149 did not have a significant effect on the Company’s financial position or results of operations.

      In May 2003, the FASB issued FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. Statement 150 establishes standards for classifying and measuring certain financial instruments that have characteristics of both liabilities and equity. The adoption of Statement 150 did not have a significant impact on the Company’s financial position or results of operations.

      In January 2003, the FASB issued FASB Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46). FIN 46 clarifies the application of existing consolidation requirements to entities where a controlling financial interest is achieved through arrangements that do not involve voting interests. Under FIN 46, a variable interest entity (“VIE”) is consolidated if a company is subject to a majority of the risk of loss from the VIE’s activities or entitled to receive a majority of the entity’s residual returns.

      Based on management’s analysis of arrangements created prior to February 1, 2003, Innovene identified BP Solvay Polyethylene North America (“BP Solvay North America”) and BP Solvay Polyethylene Europe (“BP Solvay Europe”) (collectively, the “BP Solvay Ventures”) as VIEs, based on the lack of equity at risk for Innovene’s venture partner and its obligation to absorb losses if the venture partner elected to sell its interest to Innovene. The Company further determined that it was the primary beneficiary of the BP Solvay Ventures. No other VIE’s were identified.

      Innovene retroactively applied the provisions of FIN 46 upon its adoption of the Interpretation from inception of the BP Solvay Ventures. As a result the consolidated assets, liabilities, and noncontrolling interests of the BP Solvay Ventures are reflected in Innovene’s combined financial statements using values at which these

F-17

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

amounts would have been carried in the consolidated financial statements if FIN 46 had been effective at the inception of the BP Solvay Ventures in November 2001.

      In December 2003, the Staff of the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) No. 104, Revenue Recognition, which supersedes SAB No. 101. The primary purpose of SAB No. 104 is to rescind accounting guidance contained in SAB No. 101 and the SEC’s Revenue Recognition in Financial Statements Frequently Asked Questions and Answers (the FAQ) related to multiple element revenue arrangements. Adoption of SAB No. 104 did not have a significant effect on the Company’s financial position or results of operations.

      In December 2003, FASB Statement No. 132 (revised), Employers’ Disclosures about Pensions and Other Postretirement Benefits, was issued. Statement 132 (revised) prescribes employers’ disclosures about pension plans and other postretirement benefit plans; it does not change the measurement or recognition of those plans. The Statement retains and revises the disclosure requirements contained in the original Statement 132. It also requires additional disclosures about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other postretirement benefit plans. The new annual disclosure requirements became effective for the Company as of the year ended December 31, 2004. The Company’s disclosures in Note 17 incorporate the requirements of Statement 132 (revised).

      In accordance with FASB Staff Position Nos. 106-1 and 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003, BP adopted the standard for the fiscal year beginning January 1, 2004. The provisions of the Medicare Act provide for a federal subsidy for post-retirement medical plans that provide prescription drug benefits and meet certain qualifications, and alternately would allow prescription drug plan sponsors to co-ordinate with the Medicare benefit. BP reflected the impact of the legislation by reducing its actuarially determined obligation for post-retirement medical benefits at December 31, 2004 and will reduce the net cost for post-retirement benefits in subsequent periods.

      In November 2004, the EITF reached a consensus on Issue No. 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations (EITF 03-13). Under EITF 03-13, a disposed component of an enterprise is classified as a discontinued operation only where the ongoing entity has no continuing direct cash flows and does not retain an interest, contract or other arrangement sufficient to enable the entity to exert significant influence over the disposed component’s operating and financial policies after disposal. EITF 03-13 is effective for a component of an enterprise that is either disposed of or classified as held for sale in accounting periods beginning after December 15, 2004.

Recently Issued Accounting Standards

      In December 2004, the FASB issued FASB Statement No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29. Statement 153 eliminates the Accounting Principles Board Opinion No. 29 exception for nonmonetary exchanges of similar productive assets and replaces it with an exception for exchanges of nonmonetary assets that do not have commercial substance. Statement 153 is effective for nonmonetary asset exchanges occurring in accounting periods beginning after June 15, 2005. The Company does not expect the application of Statement 153 to have a material impact on its financial position or the results of operations.

      In November 2004, the FASB issued FASB Statement No. 151, Inventory Costs an amendment of ARB No. 43, Chapter 4. Statement 151 requires that items, such as idle facility expense, excessive spoilage, double freight and re-handling costs, be recognized as current-period charges. Statement 151 also requires that the allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the

F-18

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

production facilities. Statement 151 is effective for accounting periods beginning after June 15, 2005. The Company does not expect this Statement to have a material impact on its financial position or the results of operations.

      In December 2004, the FASB issued FASB Statement No. 123 (revised 2004), Share-Based Payment (SFAS 123R). Statement 123R, which is a revision of FASB Statement No. 123, Accounting for Stock-Based Compensation, supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. Under Statement 123R, share-based payments to employees and others are required to be recognized in the income statement based on their fair value. Pro forma disclosure of the anticipated impact of Statement 123R (as disclosed above) is no longer a permitted alternative. Statement 123R has been adopted for the first interim period beginning January 1, 2005.

      In December 2004, the FASB issued Staff Position No. 109-1, Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004 (FSP 109-1). FSP 109-1, effective upon issuance, requires that the manufacturers’ deduction provided for under the American Jobs Creation Act of 2004 (the Jobs Creation Act) be accounted for as special deduction in accordance with FASB Statement No. 109, Accounting for Income Taxes, rather than a tax rate reduction. The Company will recognize the manufacturers’ deduction in the year the benefit is earned.

      In March 2005, the FASB issued FASB Interpretation No. 47 Accounting for Conditional Asset Retirement Obligations an interpretation of FASB Statement No. 143 (FIN 47). Under FIN 47, a conditional asset retirement obligation (“ARO”) represents an unconditional obligation to perform an asset retirement activity where the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 clarifies that an entity is required to recognize a liability, when incurred, for the fair value of a conditional ARO if the fair value of the liability can be reasonably estimated. Uncertainty about the timing or method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information exists. Statement 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an ARO. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset ARO. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company has not yet completed its evaluation of the impact of adopting FIN 47.

Interim Financial Information (unaudited)

      The financial statements as of June 30, 2005 and for the six-month periods ended June 30, 2005 and 2004 are unaudited; however, in the opinion of management, all adjustments, consisting solely of normal recurring adjustments necessary for a fair presentation of the financial statements for the interim periods, have been included. The results of operations for the six-months ended June 30, 2005 are not necessarily indicative of the results to be achieved for the full fiscal year.

(4) Relationship with BP

      The Company engages in transactions with BP and BP’s subsidiaries in the normal course of business. These transactions include the purchase of feedstock used as raw material by the Company as well as the sharing of certain infrastructure sites. Additionally, the Company utilizes centralized functions of BP to support its operations and in return, BP allocates certain of its expenses to the Company. Such intercompany transactions are included in Transfers from Parent net investment in the combined financial statements unless directly traceable to a third party.

      Funding is derived from inter-company transactions with BP, from operations, or other sources. Cash requirements met through transfers from BP include funds used to purchase investments, to fund operating losses

F-19

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

and for other liquidity needs. All transaction activity between Innovene and BP is netted and recorded as Transfers to/from parent within Parent net investment. Except for interest accrued on a short-term note extended upon legal separation on April 1, 2005, no intercompany interest charges have been recognized between BP and the Company.

      Transactions with BP Group are summarized in the table below:

	For the year ended
	December 31,
	2002			2003			2004
	($ in millions)
Sales to BP		3,589			4,385			6,145
Purchases from BP		(3,670	)		(2,869	)		(2,703	)
Selling, general, and administrative(1)		(145	)		(164	)		(259	)

Note:

(1)  Selling, general and administrative comprises corporate cost allocations and recharges from functions hosted elsewhere within BP.

     The BP Group was both the Company’s most significant customer and supplier, accounting for over 10% of the Company’s total revenues and purchases. The majority of sales were generated from the Company’s refining segment, all of which historically were sold on by BP to third parties. Purchases were made across all segments of the Company.

Corporate Cost Allocations

      Certain expenses reflected in the combined statement of operations include allocations of costs from BP. Such expenses represent costs related to treasury, legal, insurance, payroll administration, human resources, and other services. These costs, together with an allocation of central BP overhead costs, are included within selling, general, and administrative expenses, as described above. Where it is possible to specifically attribute such expenses to activities of the Company, these amounts have been charged or credited directly to the Company without allocation or apportionment. Allocation of all other such expenses is based on factors depending on the relevant respective activity.

      Where employees of the Company participate in pension and other post-employment benefit arrangements sponsored by BP, the Company has reflected the cost BP incurs on its behalf of providing the pensions as a charge (or credit) to income based on the number of the Company’s active employees.

      BP also sponsors other benefit plans, including profit sharing plans, incentive plans and stock purchase plans in which Company employees participate. Costs related to these plans are allocated to the Company according to an analysis of the number of current and historic employees.

      In management’s opinion, the methods used in allocating expenses are reasonable. However, resulting expenses may not represent the amounts that would have been incurred had such transactions been entered into with third parties at “arm’s length”.

      For purposes of governing certain of the ongoing relationships between Innovene and BP at and after the Separation and to provide for an orderly transition, Innovene and BP have entered into various agreements. A brief description of each of the material agreements follows.

F-20

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

Reorganization Agreements

      The following are some key reorganization agreements in connection with interfaces with BP.

Local Transfer Agreements

      Effective April 1, 2005, BP transferred to separate legal entities substantially all of the assets and liabilities relating to the former olefins and derivatives business of BP’s Petrochemicals segment, the Company’s refineries at Grangemouth, United Kingdom, and Lavéra, France, which formed part of BP’s Refining and Marketing segment, and the gas fractionator located near Hobbs, New Mexico, which formed part of BP’s Gas, Power and Renewables segment, in each case, together with associated infrastructure. The transfers were made on the basis of a series of Local Transfer Agreements for each country in which the Company has operations. As a result of these transfers, the separate legal entities acquired BP’s title or other interest in the relevant assets and, with limited exceptions, the unencumbered ability to operate and transfer their assets to third parties.

Master Reorganization Agreement

      The amended and restated Master Reorganization Agreement sets out a framework for dealing with assets or liabilities not specifically covered by the Local Transfer Agreements described above, such as liabilities arising from the Company’s or BP’s past and future conduct. Subject to the exceptions described in the agreement, the Company generally has agreed to assume, and indemnify BP for, all liabilities relating to the assets BP has transferred to the Company, and BP has agreed to retain, and indemnify the Company for, all liabilities relating to assets BP has retained. In each case, these indemnities cover all losses arising from such liabilities, regardless of whether they arise from events occurring before or on or after April 1, 2005.

New Common Terms Memorandum

      The Company also entered into a New Common Terms Memorandum with BP where it and BP have agreed to transfer restrictions on the Company’s assets in connection with certain of the commercial interface agreements as described below. Under these restrictions, neither the Company nor BP can transfer an asset reasonably related to any relevant commercial interface agreement to a non-affiliated third party without assigning that commercial interface agreement to the same third party. Such assignment of the relevant commercial interface agreement by the Company or BP will require prior consent of the other party, but the other party may refuse prior consent only if it is reasonable to believe that the unaffiliated transferee will not act as a reasonable and prudent operator under the agreement or does not have sufficient financial standing to perform the obligations under the agreement.

Intellectual Property and Information Technology Separation Agreement

      The Company has entered into an Intellectual Property and Information Technology Separation Agreement (IPITSA) with BP, which governs the transfer of intellectual property and intellectual property related agreements from BP to the Company and addresses certain related third-party issues. The IPITSA provides for the transfer from BP to the Company of certain registered patents, trademarks and domain names along with any other intellectual property relating exclusively to the Company’s petrochemical business, the Company’s refineries in Grangemouth, United Kingdom, and Lavéra, France, and the Company’s gas fractionator near Hobbs, New Mexico. In addition, BP has agreed to assign to the Company all intellectual property-related contracts, such as licenses, research and development agreements, technology sharing agreements, software licenses and support agreements relating exclusively to the Company’s business. BP has also granted the Company licenses in respect of certain intellectual property in which the Company and BP have a common interest under separate common interest intellectual property agreements.

F-21

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

U.S. Master Tax Agreement

      BP and the Company have entered into a U.S. Master Tax Agreement pursuant to which BP has agreed to retain, and indemnify the Company for, among other things, the U.S. tax liabilities arising prior to April 1, 2005, including any income and franchise and other taxes measured by income incurred as a result of transferring assets to the Company, and the Company has agreed to assume, and indemnify BP for, among other things, the U.S. tax liabilities arising on or after April 1, 2005. Any other separation-related U.S. tax liabilities generally will be paid by the party legally responsible and BP and the Company have agreed to cooperate in the resolution of such taxes. The Company additionally will be liable should it take any actions that trigger recapture of taxes in respect of any foreign affiliate to the extent that prior losses claimed in relation to such affiliate by the BP U.S. Federal consolidated group were certified to only be deductible by the BP U.S. Federal consolidated group (i.e., dual consolidated losses). The U.S. Master Tax Agreement also deals with the ongoing relationship between the Company and BP in relation to other U.S. tax matters, for example, in relation to tax compliance, and includes provisions which allow both parties to share tax assets, subject to appropriate compensation payments.

Rest of the World Tax Agreement

      Under the Rest of the World tax Agreement, BP has generally agreed to retain, and indemnify the Company for, among other things, non-U.S. tax liabilities arising prior to April 1, 2005 including any income and other taxes measured by income which are incurred as a result of transferring assets to the Company, and the Company has generally agreed to assume, and indemnify BP for, among other things, non-U.S. tax liabilities arising on or after April 1, 2005. Any other separation-related non-U.S. tax liabilities generally will be paid by the party on which it has been assessed provided that all transfer taxes will be borne by the Company. The Rest of the World Tax Agreement also deals with the ongoing relationship between the Company and BP in relation to other non-U.S. tax matters, for example, in relation to tax compliance, and includes provisions which allow both parties to share tax assets, subject to appropriate compensation payments.

Net Transfers Upon Legal Separation

      Effective April 1, 2005, certain transactions occurred in accordance with the agreements between BP and the Company. The results of these transactions have been recorded as adjustments to the parent company investment in the Company. The result of these transactions was to increase the Parent Net Investment in the Company by $589 million.

      On the basis of the Local Transfer Agreements between the Company and BP for each country in which the Company has operations, the separate legal entities of the Company acquired title to assets and operations from other entities of BP.

Income Taxes

      On April 1, 2005, the Company received its assets from BP in a taxable asset transaction; accordingly, the Company will obtain a depreciable basis equal to the fair market value of the assets received from BP. The majority of non-U.S. asset transfers were taxable such that the depreciable assets are recorded at fair market value for tax purposes. Accordingly, the existing deferred tax asset and liability balances were reversed through Parent Net Investment and a deferred tax asset recorded, with an offsetting entry to equity, to the extent that the tax depreciable basis exceeded the depreciable net book value. The net effect of these transactions was to increase Parent Net Investment by $483 million.

      In the U.S., pursuant to the terms of the U.S. Master Tax Agreement, the Company will not be entitled to the benefits of the depreciation associated with this additional tax basis until the Company is no longer included in

F-22

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

the BP U.S. consolidated tax return. This will occur when BP’s ownership in the Company is less than 80%. As the Company currently is wholly-owned by BP no adjustment to the existing tax position was made as of April 1, 2005.

Grangemouth assets and Geel Infrastructure

      Certain of the asset transfers made in accordance with the Local Transfer Agreements resulted in BP transferring to the Company certain assets and the Company transferring to BP certain assets. Among those assets transferred to the Company were certain logistic assets at the Grangemouth, UK site. Among the assets transferred by the Company to BP were certain previously shared assets at the Grangemouth, UK site and the Geel, Belgium site. The net effect of these transfers was to decrease Parent Net Investment in the Company by $25 million.

Pensions

      In accordance with the Master Reorganization Agreement, BP agreed to retain the obligations for retirees related to the Company’s pension plans in Germany. The effect of this is to increase the Parent Net Investment by $262 million. The Company has agreed to certain reimbursement arrangements with BP related to its U.S. post-retirement health care obligations and other unfunded arrangements related to the U.S. and France. The effect of this was to decrease Parent Net Investment by $52 million.

Other

      Other Reorganization Agreements between BP and the Company have resulted in an increase in Parent Net Investment of $14 million. These primarily relate to BP agreeing to assume certain obligations previously recorded by the Company’s predecessor operations.

      The tax effects of transactions other than tax related to the legal separation reduced Parent Net Investment by $93 million.

Commercial Interface Agreements

      The Company has entered into a series of commercial interface agreements with BP to maintain and enhance its existing relationships by establishing medium- to long-term arrangements for services, utilities and infrastructure access rights in situations where the Company or BP depend on each other or where reasonable alternatives do exist but it is nevertheless economical for the Company and BP to continue pre-existing arrangements. The Company has also established agreements for the sale and purchase of refining and petrochemical feedstocks and refined products in situations where the Company or BP have an interest in establishing a secure source of feedstock supply or ensure the off-take of products, with the term of these agreements in part depending on the availability of third-party alternatives. In addition, the Company has entered into various agreements for the provision by BP to the Company of short-term transitional services, such as information technology infrastructure, which the Company cannot readily replicate as a new company but which it expects to have the ability to provide in-house or outsource to a third party at the end of the initial term of these agreements.

      Each of the major commercial interface agreements are briefly summarized below.

Hydrocarbons Sale and Purchase Agreements

      The Hydrocarbons Sale and Purchase Agreements govern the sale and purchase of petrochemical and refining feedstocks at or between sites where the Company and BP have a continuing relationship with each other. Each of the agreements is in substantially the same form, with only minor jurisdiction and site-specific differences. Each agreement is a master agreement describing the general terms and conditions on which the relevant feedstocks are sold and purchased as between the Company and BP. The commercial terms for each

F-23

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

relevant petrochemical or refining feedstock are set out in a separate term sheet appended to the relevant agreement.

Supply and Trading Agreements

      The Company has entered into various Supply and Trading Agreements with BP under which BP will, for a limited period of time, provide the Company with certain supply, trading and optimization services in areas in which the Company currently has no, or limited, in-house capability. The agreements have been structured so as to enable the Company to develop the necessary capabilities in-house by the end of the initial term of these agreements. The main agreements may be divided into Master Services Agreements and Sale and Purchase Agreements. The Company has also entered into a series of Foreign Exchange and Precious Metals Agreements with BP for the provision of foreign exchange and interest rate services and services relating to the sale and/or lease of certain precious metals used as catalysts.

Inland Refined Products Sale and Purchase Agreements

      The Company has entered into Inland Refined Products Sale and Purchase Agreements with BP for the domestic sale of certain refined products. The Company has entered into separate agreements for its Grangemouth, United Kingdom, and Lavéra, France, refineries. Under each agreement, BP has agreed to purchase all of the refined products the Company sells into the relevant domestic market at market-based prices for the term of the respective agreements and related term sheets.

Framework Interface Agreements

      The Company has entered into various Framework Interface Agreements for the provision by the Company to and vice-versa BP of services and utilities at certain shared sites and in some cases between our respective sites. These agreements range from short-term, transitional arrangements for services which the Company will eventually establish on an in-house basis or will outsource to an alternative supplier to long-term arrangements in areas where the Company and BP depend on each other.

Site Cooperation Agreements

      The Company has entered into various Site Cooperation Agreements with BP to establish rules and procedures to facilitate its operations at certain key sites that the Company shares with BP. The Company has agreements in place for its sites in Carson, California, Naperville, Illinois, Texas City, Texas, Whiting, Indiana, Geel, Belgium, and Grangemouth, United Kingdom.

F-24

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

(5) Other Income (Expense)

      Other income (expense) consisted of the following:

										For the
										six months
	For the year ended									ended
	December 31,									June 30,
	2002			2003			2004			2004		2005
										(unaudited)
	($ in millions)
Gain (loss) from disposals of fixed assets		25			(7	)		—			—		—
Gain (loss) from foreign exchange revaluation net of gains (losses) from derivatives		20			49			78			13		3
Decrease (increase) in the fair value of the BP Solvay Ventures put liabilities		(128	)		(168	)		(105	)		10		—
Accelerated interest on loan termination		—			—			—			—		(45	)
Other		18			3			3			4		—
Total		(65	)		(123	)		(24	)		27		(42	)

(6) Inventories

      Inventories consisted of the following:

	As of
	December 31,				As of
					June 30,
	2003		2004		2005
					(unaudited)
	($ in millions)
Crude oil		251		323		478
Oil products		196		235		306
Petrochemicals products		792		1,061		1,072
Total inventories		1,239		1,619		1,856
Stores		154		127		174
		1,393		1,746		2,030

      As disclosed in Note 3, the Company values the majority of inventories in the United States using the LIFO method. At December 31, 2003 and 2004 and June 30, 2005, the excess of current cost over the stated LIFO value was $102 million, $228 million, and $194 million, respectively.

F-25

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

(7) Other Current Assets

      Prepayments and other current assets are summarized as follows:

	As of
	December 31,				As of
					June 30,
	2003		2004		2005
					(unaudited)
	($ in millions)
Prepayments and other accrued income		73		77		131
Taxes and duties		83		98		209
Derivative instruments		204		155		—
Other		124		337		260
Total		484		667		600

(8) Property, Plant, and Equipment

      Property, plant, and equipment are summarized as follows:

	As of
	December 31,
	2003			2004
	($ in millions)
Land		100			109
Buildings		415			472
Machinery and equipment		11,350			11,939
Construction in progress		403			493
Total		12,268			13,013
Less accumulated depreciation		(5,218	)		(5,877	)
Net		7,050			7,136

      Depreciation expense from continuing operations for the years ended December 31, 2002, 2003, and 2004 was $406 million, $492 million, and $527 million, respectively.

(9) Consolidation of Variable Interest Entities

      Innovene adopted FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which addresses the consolidation of variable interest entities (“VIEs”). Under FIN 46, arrangements that are not controlled through voting or similar rights are accounted for as VIEs. An enterprise is required to consolidate a VIE if it is the primary beneficiary of the VIE.

      Under FIN 46, a VIE is created when (i) the equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support from other parties or (ii) equity holders either (a) lack direct or indirect ability to make decisions about the entity through voting or similar rights, (b) are not obligated to absorb expected losses of the entity or (c) do not have the right to receive expected residual returns of the entity if they occur. If an entity is deemed to be a VIE, pursuant to FIN 46, an enterprise that absorbs a majority of the expected losses or residual returns of the VIE is considered the primary beneficiary and must consolidate the VIE.

F-26

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      Innovene’s analysis of its arrangements identified BP Solvay North America and BP Solvay Europe as VIEs. This determination primarily was based on a put instrument held by Innovene’s venture partner allowing the partner to put its interest in the BP Solvay Ventures to Innovene at specified dates and at specified prices. The pricing of the put arrangement effectively resulted in the obligation by Innovene to absorb losses of the BP Solvay Ventures. Innovene further determined that it was the primary beneficiary as a result of its obligations under the put instrument.

      The BP Solvay Ventures were formed for the purpose of manufacturing and selling high density polyethylene in Europe and North America. Innovene held a 50% voting interest in BP Solvay Europe entities and a 49% interest in the BP Solvay North America entity. Innovene retroactively applied the provisions of FIN 46 upon its adoption of the Interpretation from inception of the BP Solvay Ventures. As a result the assets, liabilities and noncontrolling interests have been consolidated in Innovene’s combined financial statements from November, 2001. The noncontrolling interests have been included as Minority Interest in the Combined Balance Sheets. Changes in the fair value of the BP Solvay Ventures put liabilities from the date of initial consolidation to exercise of the put have been recognized as Other income (expense) in the Combined Statement of Operations.

      On November 2, 2004, the Company’s former venture partner in the BP Solvay Ventures exercised its option to sell its interests in the two joint ventures to Innovene at the previously determined and established prices based on the terms of the put instrument. On completion, the two ventures, which manufacture and market high-density polyethylene, became wholly-owned subsidiaries of BP.

(10) Discontinued Operations

      During 2004, Innovene’s management committed to a plan to sell its butanediol (“BDO”) operations based in Lima, Ohio. As a result of this commitment, the Company recorded a charge of $148 million to record the BDO asset group at fair value less cost to sell. For reporting purposes, the results of operations related to BDO, including the 2004 impairment charge, are classified as discontinued operations for all periods presented. In the first quarter of 2005, the Company signed a definitive sales agreement and closed the sale. There was no gain or loss on disposal following the impairment charge recorded in 2004.

      The major classes of assets and liabilities of discontinued operations included in the Combined Balance Sheets are summarized as follows:

		As of
		December 31,
		2003			2004
		($ in millions)
Current assets			34			15
Non-current assets			144			—
	Total assets of discontinued operations		178			15
Current liabilities			(6	)		(10	)
Non-current liabilities			(34	)		—
	Total liabilities of discontinued operations		(40	)		(10	)

F-27

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

(11) Goodwill and Other Intangible Assets

Goodwill

      Upon adoption of FASB Statement No. 142 on January 1, 2002, the Company ceased to amortize goodwill.

      The Company’s goodwill balance relates solely to the Olefins and Polymers Europe segment.

      The following table summarizes the changes in the Company’s goodwill balance during 2003 and 2004:

	($ in millions)
Balance at December 31, 2002		26
Effect of exchange rate on translation		5
Balance at December 31, 2003		31
Effect of exchange rate on translation		3
Balance at December 31, 2004		34

Other Intangible Assets

      The Company does not have any indefinite-lived Other Intangible Assets. The gross carrying amounts and accumulated amortization in total and by major class of other intangible assets are as follows:

	As of December 31, 2003
			Accumulated
	Gross		Amortization			Net
	($ in millions)
Intangible assets subject to amortization (definite-lived):
Pension — unamortized prior service costs		32		—			32
Capitalized software development costs		78		(13	)		65
Favorable contracts (customer lists, distribution logistics)		116		(16	)		100
Technology		25		(3	)		22
Other		33		(24	)		9
		284		(56	)		228

	As of December 31, 2004
			Accumulated
	Gross		Amortization			Net
	($ in millions)
Intangible assets subject to amortization (definite-lived):
Pension — unamortized prior service costs		32		—			32
Capitalized software development costs		90		(18	)		72
Favorable contracts		116		(23	)		93
Technology		25		(5	)		20
Other		37		(27	)		10
		300		(73	)		227

F-28

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      Amortization expense from continuing operations for the years ended December 31, 2002, 2003, and 2004 was $17 million, $25 million, and $18 million, respectively.

      Estimated future amortization expense for intangible assets through December 31, 2009 is $16 million annually.

(12) Other Current Liabilities

      Other current liabilities consist of the following:

	As of
	December 31,				As of
					30 June
	2003		2004		2005
					(unaudited)
	($ in millions)
Deferred income		8		6		5
Restructuring		84		97		81
Taxes and duties		3		31		156
Short term debt held in affiliate		—		82		—
Other		101		136		81
Total		196		352		323

      Short term debt was held from December 27, 2004 and repaid on January 3, 2005.

(13) Debt

Long term debt

      The combined balance sheets include long-term loans of $1,585 million and $1,729 million at December 31, 2003 and 2004, respectively, for borrowings secured by certain of the Olefins & Polymers Europe assets located at the Grangemouth site in the United Kingdom.

      The borrowings have terms of between 20 and 30 years and would have matured between 2018 to 2022. The average rate of interest for these loans was 3.14%, 3.16% and 3.58% for the years ended December 31, 2002, 2003 and 2004, respectively. The related interest charges total $37 million, $45 million and $58 million for the years ended December 31, 2002, 2003 and 2004, respectively.

      According to the terms of the long term loans, Innovene was required to pledge assets to secure a portion of the outstanding loan balance. In accordance with the loan terms, the net book value of the assets securing these loans was $643 million and $652 million at December 31, 2003 and 2004, respectively.

Short term debt

      In anticipation of the separation of the Company from BP, the long-term debt was repaid in full by the Company on March 22, 2005 for $1,755 million. This funding was replaced with a $1,700 million short-term interest-bearing loan from the Parent, with an interest rate of LIBOR plus five basis points. The termination payment on the debt exceeded the book value resulting in a loss being recognised on extinguishment of the debt of $45 million which is included in Other income (expense) in the Combined Statements of Operations.

F-29

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

(14) Other Non-current Liabilities

      Other non-current liabilities consist of the following:

	As of
	December 31,
	2003		2004
	($ in millions)
Pension and other post-employment benefits		443		528
Deferred income		14		10
Other		24		15
Total		481		553

(15) Impairments and Restructuring Charges

      Restructuring activities represent the integration of acquisitions into the business, divestment activities, as well as ongoing cost rationalization programs at manufacturing sites and other locations.

      As of December 31, 2003, the Company had reserves for severance related cost and site exit and other costs of $51 million and $33 million, respectively. During the year ended December 31, 2004, the Company recorded additional charges of $345 million, including $280 million of charges for asset impairment and write downs, and $65 million of costs for workforce reductions, demolition and decommissioning and other restructuring costs. For the purposes of measuring impairment charges, the fair value of the assets was largely determined by using the

F-30

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

present value of expected cash flows or expected sales proceeds, depending on the circumstances. During the 2004 period, the Company made cash payments against reserves of $56 million.

		Write-down			Severance-related			Site exit and
		of assets			costs			other costs			Total
		($ in millions)
Accrued liabilities as of December 31, 2001			—			64			64			128
	Charges during the period		32			32			29			93
	Payments during the period		—			(39	)		(32	)		(71	)
	Asset write offs		(32	)		—			—			(32	)
	Exchange rate movements		—			3			2			5
Accrued liabilities as of December 31, 2002			—			60			63			123
	Charges during the period		36			26			10			72
	Payments during the period		—			(42	)		(47	)		(89	)
	Asset write offs		(36	)		—			—			(36	)
	Exchange rate movements		—			7			7			14
Accrued liabilities as of December 31, 2003			—			51			33			84
	Charges during the period		280			19			46			345
	Payments during the period		—			(33	)		(23	)		(56	)
	Asset write offs		(280	)		—			—			(280	)
	Exchange rate movements		—			3			1			4
Accrued liabilities as of December 31, 2004			—			40			57			97
	Charges during the period		—			21			—			21
	Payments during the period		—			(21	)		(2	)		(23	)
	Transfer to parent net investment		—			(13	)		(1	)		(14	)
Accrued liabilities as of June 30, 2005 (unaudited)			—			27			54			81

F-31

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      Restructuring accruals by reportable segments are summarized as follows:

		Olefins and
		Polymers
					North			Global						Corporate
		Europe			America			Derivatives			Refining			and Other			Total
		($ in millions)
Accrued liabilities as of December 31, 2001			101			8			16			—			3			128
	Charges during the period		32			20			1			12			28			93
	Payments during the period		(45	)		(6	)		(4	)		—			(16	)		(71	)
	Asset write offs		—			(20	)		—			(12	)		—			(32	)
	Exchange rate movements		5			—			—			—			—			5
Accrued liabilities as of December 31, 2002			93			2			13			—			15			123
	Charges during the period		26			—			4			41			1			72
	Payments during the period		(67	)		—			(4	)		(5	)		(13	)		(89	)
	Asset write offs		—			—			—			(36	)		—			(36	)
	Exchange rate movements		12			—			1			—			1			14
Accrued liabilities as of December 31, 2003			64			2			14			—			4			84
	Charges during the period		83			—			228			7			27			345
	Payments during the period		(39	)		(2	)		(5	)		(7	)		(3	)		(56	)
	Asset write offs		(76	)		—			(185	)		—			(19	)		(280	)
	Exchange rate movements		3			—			1			—			—			4
Accrued liabilities as of December 31, 2004			35			—			53			—			9			97
	Charges during the period		—			—			—			—			21			21
	Payments during the period		(6	)		—			(1	)		—			(16	)		(23	)
	Transfer to parent net investment		—			—			—			—			(14	)		(14	)
Accrued liabilities as of June 30, 2005 (unaudited)			29			—			52			—			—			81

First Half 2005 Segmental Restructuring Activity and Impairments

      As of December 31, 2004, the Olefins and Polymers Europe segment reserve consisted of $35 million related to the restructuring activities at the Grangemouth, UK site (as announced in 2003), the restructuring activities at the Lavéra, France site (as announced in 2000 and 2002), the restructuring activities at the Geel, Belgium site (as announced in 2000 and 2003) and the integration of the BP Solvay entities. During the six months ended June 30, 2005, the segment made cash payments of $6 million.

      As of December 31, 2004, the Corporate and Other segment reserve consisted of $9 million related to the restructuring of the global Research & Technology support function and facilities and liabilities in respect of workforce reduction across the global operations. During the six months ended June 30, 2005, the segment recorded additional restructuring charges of $21 million in respect of further global workforce reductions. Cash payments were $16 million in the six months ended June 30, 2005. The reserve balance as of April 1, 2005 was retained by BP and the $14 million was reclassified to Parent net investment.

      As of December 31, 2004, the Global Derivatives segment reserve consisted of $53 million, related to the closure of the Pasadena, North America site (as announced in 2004) and the restructuring activities at the Feluy, Belgium site (as announced in 2001). Cash payments were $1 million in the six months ended June 30, 2005.

F-32

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

2004 Segmental Restructuring Activity and Impairments

      As of December 31, 2003, the Olefins and Polymers Europe segment reserve consisted of $64 million related to the restructuring activities at the Grangemouth, UK site (as announced in 2003), the restructuring activities at the Lavéra, France site (as announced in 2000 and 2002), the restructuring activities at the Geel, Belgium site (as announced in 2000 and 2003) and the integration of the BP Solvay entities. During the year ended December 31, 2004, the segment recorded additional charges of $83 million consisting of asset impairments at the Grangemouth site ($69 million) and within the Solvay JV, Belgium ($7 million) and $7 million of other charges and made cash payments of $39 million. As of December 31, 2004 the balance of the Olefins and Polymers Europe segment reserve totaled $35 million.

      As of December 31, 2003, the Global Derivatives segment reserve consisted of $14 million related to the restructuring activities at the sites in Feluy, Belgium (as announced in 2001), Texas City, North America (as announced in 2001), and Whiting, North America (as announced in 2001). During the year ended December 31, 2004, the segment recorded additional charges of $228 million consisting of $185 million of asset impairment and $43 million of other charges and made cash payments of $5 million. The charges followed the Company’s decision to exit the Pasadena, North America site (as announced in December 2004). As of December 31, 2004 the balance of the Global Derivatives segment reserve totaled $53 million.

      During the year ended December 31, 2004, the Refining segment recorded restructuring charges and made cash payments of $7 million relating to the Grangemouth, UK site.

      As of December 31, 2003, the Corporate and Other segment reserve consisted of $4 million related to the restructuring of the global Research & Technology support function and facilities. During the year ended December 31, 2004, the segment recorded additional charges of $27 million consisting of $19 million of asset impairment and $8 million of other charges and made cash payments of $3 million. The asset impairment in the Licencing business relates to the decision to exit the butanediol (“BDO”) business (see Note 10). The charges are in respect of workforce reductions across the global operation. Further workforce reductions resulted in additional restructuring charges of approximately $21 million in 2005. As of December 31, 2004 the balance of the Corporate and Other segment reserve totaled $9 million.

2003 Segmental Restructuring Activities and Impairments

      During the year ended December 31, 2003, the Olefins and Polymers Europe and Refining segments announced a joint transformation program at the Grangemouth, UK site. Restructuring charges of $20 million were recorded for estimated workforce reductions of 190 employees.

      During the year ended December 31, 2003, the Refining segment recorded $36 million of asset impairment in respect of units at the Grangemouth, UK site.

      During the year ended December 31, 2003, the Olefins and Polymers Europe segment recorded $11 million of charges in respect of the restructuring of the Solvay, UK and Geel, Belgium sites.

2002 Segmental Restructuring Activities and Impairments

      During the year ended December 31, 2002, the Olefins and Polymers Europe segment recorded $38 million charges in respect of the integration of the BP Solvay entities ($28 million, announced 2001), the cessation of Ethylene Oxide-based Glycol Ether manufacturing at the Lavéra site ($8 million, fourth quarter of 2002) and the anticipated final costs associated with the closure of a sales and administrative office in Geneva, Switzerland ($2 million, announced 2000). The net charge included the reversal of a $6 million historical provision relating to the Grangemouth, UK site (announced in 2000).

F-33

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      During the year ended December 31, 2002, the Olefins and Polymers North America segment recorded a $20 million asset impairment following the decision to close a polypropylene production line at the Chocolate Bayou, North America site in the first quarter of 2002.

      During the year ended December 31, 2002, the Refining segment recorded a $12 million asset impairment in respect of a redundant pipeline at the Grangemouth, UK site.

      During the year ended December 31, 2002, the Corporate and Other segment recorded $28 million of charges in respect of the restructuring of the global Research & Technology support function and facilities ($21 million, announced second quarter of 2002), the refit of an administrative office at Naperville, North America ($3 million) and sundry functional transformation projects.

(16) Employee Benefit Plans

BP Pension and Other Post-Employment Benefit Plans (Group Plans)

      A number of the Company’s employees in the United States, United Kingdom, Canada and Belgium participate in BP pension and other post-employment benefit plans (the Group Plans). BP pension plans typically provide pension payments that depend on an employee’s length of service and earnings at, or near, retirement or have a “cash balance” design. Such plans are funded by the employer, and in certain countries employee contributions to external funds, with contributions and costs being determined after receiving advice from independent actuaries.

      BP also provides post-retirement healthcare benefits and post-retirement life insurance that reimburse healthcare costs for retirees and dependants, or pay a lump sum to a beneficiary’s spouse upon death. Entitlement to these benefits is generally based on an employee’s service at retirement. The cost of providing post-retirement healthcare benefits and post-retirement life insurance is assessed annually by independent actuaries.

      BP determines pension and post-employment benefit cost for its Group Plans on a consolidated basis and therefore accurate information relating to the Company’s assets and obligations cannot be determined with any certainty prior to April 1, 2005. For the years ended December 31, 2002, 2003 and 2004 and the three months ended March 31, 2005 the Statements of Operations include an allocation to the Company of the benefit costs of the Group Plans. The costs for retirees and former employees of the BP Group Plans were allocated based on the Company’s active employee population from each of the periods presented.

      In relation to the Company’s participation in the Group Plans, the Company recorded pension and other post-employment benefit amounts for the three years ended December 31, 2004 as follows:

	For the year ended
	December 31,
	2002			2003			2004
	($ in millions)
Pension expense/(credit)		(25	)		(23	)		32
Other post employment benefits		17			22			23
Total expense/(credit)		(8	)		(1	)		55

      Prior to January 1, 2004, a net pension credit is reported due to the combined effect of the unrecognized actuarial gain and unrecognized transitional gain being amortized through the pension expense. The transitional obligation was fully amortized by December 31, 2003 and the actuarial gain recorded in prior years has reversed to become an actuarial loss for the year ended December 31, 2004.

F-34

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      The pension and other post-employment benefit amounts recognized in future periods could be materially different from these amounts, principally because pension and other post-employment obligations relating to retired and terminated vested Group Plan employees prior to April 1, 2005 remained the responsibility of BP, and the Company has generally continued to participate in the Group Plans from April 1, 2005 under the terms of the Master Reorganization Agreement. From April 1, 2005 and until BP’s shareholding in Innovene falls below 50% (80% in the US) Innovene will pay to BP the International Financial Reporting Standards (“IFRS”) Service Cost for Innovene employees who continue to participate in the BP Group funded plans and reimburse BP for benefits paid to Innovene employees who continue to participate in the BP Group unfunded arrangements and who reach eligibility after March 31, 2005.

      BP’s U.S. tax-qualified pension plan has a design that is based in part upon a “cash balance” formula. It should be noted that in 2003, a Federal district court in Illinois ruled that the benefit formula used in International Business Machines Corporation’s (IBM) cash balance pension plan violated the age discrimination provisions of ERISA and that IBM must make back payments to workers covered under the plan. The IBM decision conflicts with decisions of at least three other district courts, including most recently a June 2004 decision of the Federal district court in Maryland. Proposed regulations validating the cash balance design have been withdrawn by the Treasury Department while Congress considers legislative action to clarify the legal status of cash balance plans under age discrimination rules. At this time, it is unclear what effect, if any, these decisions or Congressional or regulatory action may have on BP’s tax-qualified pension plan.

Company Pension and Other Post-employment Benefit Plans

      The Company sponsors pension and other post-employment benefit plans for certain of its employees in the U.S., France and Germany. The pension plans provide payments to eligible employees upon retirement. Pension benefits for employees are generally based on an employee’s length of service, and in the case of France, earnings at or near retirement. Other post-employment benefits are in the form of lump sum benefits that depend on an employee’s length of service and earnings at, or near retirement, and post-employment healthcare benefits that reimburse healthcare costs for retirees and dependants. The BP Solvay North America Pension Plan is funded by the Company. Contributions to external funds are determined after receiving advice from independent actuaries. The other pension and other post-employment benefit plans are unfunded in line with local practice.

      The cost of providing pension and other post-employment benefits is assessed annually by independent actuaries.

      Pension plan assets for funded arrangements are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligations of the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in portfolio management.

      A significant proportion of the assets are held in equities owing to a higher expected level of return over the long term with an acceptable level of risk. In order to provide a reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment portfolios are diversified.

      The asset allocation for the major funded Company pension plan (BP Solvay North America) at December 31, 2002, 2003 and 2004 was as follows:

Asset category	2002			2003			2004
Equities		66	%		66	%		67	%
Bonds		34	%		34	%		33	%

F-35

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      Return on asset assumptions reflect the Company’s expectations built up by asset class. The Company’s expectation is derived from a combination of historical returns over the long term and forecasts of market professionals.

Plan Obligations, Assets and Funded Status at December 31:

										Other Post-
	Pension Benefits									employment Benefits
Change in benefit	2002			2003			2004			2002		2003			2004
	($ in millions)
Benefit obligation at beginning of year		222			324			443			17		21			21
Service cost		5			15			18			1		1			1
Interest cost		14			20			24			1		1			1
Benefits paid		(15	)		(24	)		(29	)		—		—			—
Plan amendments		19			—			7			—		—			—
Curtailments		—			31			4			—		—			—
Actuarial loss (gain)		34			8			35			1		(3	)		1
Foreign currency exchange rate changes		45			69			42			1		1			1
Benefit obligation at end of year		324			443			544			21		21			25

										Other Post-
	Pension Benefits									employment Benefits
Change in plan assets	2002			2003			2004			2002			2003			2004
	($ in millions)
Fair value of plan assets at beginning of year		1			4			4			—			—			—
Employer contributions		18			24			33			—			—			—
Plan participants’ contributions		—			—			—			—			—			—
Benefits paid		(15	)		(24	)		(29	)		—			—			—
Fair value of plan assets at end of year		4			4			8			—			—			—
Funded status at end of year		(320	)		(439	)		(536	)		(21	)		(21	)		(25	)
Unrecognized prior service cost		36			41			50			—			—			(1	)
Unrecognized net actuarial loss		40			56			94			5			2			5
Net amount recognized		(244	)		(342	)		(392	)		(16	)		(19	)		(21	)

Amounts recognized in the Combined Financial Statements at December 31:

										Other Post-
	Pension Benefits									employment Benefits
	2002			2003			2004			2002			2003			2004
	($ in millions)
(Accrued) benefit cost		(305	)		(424	)		(507	)		(16	)		(19	)		(21	)
Intangible assets		29			32			32			—			—			—
Accumulated other comprehensive income		32			50			83			—			—			—
Net amount recognized		(244	)		(342	)		(392	)		(16	)		(19	)		(21	)

F-36

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      The Accumulated Benefit Obligation for defined benefit pension plans was $297 million, $414 million and $505 million respectively as of December 31, 2002, 2003 and 2004, respectively.

Components of net periodic benefit cost:

	For the year ended							For the six months
	December 31,							ended June 30,
	2002			2003		2004		2004		2005
								(unaudited)
	($ in millions)
Pension benefits:
Service cost		5			15		18		9		11
Interest cost		14			20		24		12		10
Amortization of prior service cost		1			2		2		1		1
Amortization of net loss (gain)		(1	)		3		3		2		2
Curtailments		—			31		4		—		—
Net periodic benefit cost for pension benefits		19			71		51		24		24
Other Post-employment benefits:
Service cost		1			1		1		—		—
Interest cost		1			1		1		1		1
Amortization of prior service cost		—			—		—		—		—
Amortization of net loss (gain)		—			—		—		—		—
Curtailments		—			—		—		—		—
Net periodic benefit cost for other post-employment benefits		2			2		2		1		1
Total net periodic benefit cost		21			73		53		25		25

      Pension plan contributions paid during the six months ended June 30, 2004 and June 30, 2005 were $15 million and $11 million respectively. Expected contributions for the year ended December 31, 2005 are $15 million. Expected other post-employment benefit contributions for the year ended December 31, 2005 are $0 million.

Additional information:

	Pension Benefits
	2002		2003		2004
	($ in millions)
Increase in minimum liability included in other comprehensive income		24		18		33

F-37

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

Weighted average assumptions used to determine benefit obligations at December 31:

	Pension Benefits									Other Post-employment Benefits
	2002			2003			2004			2002			2003			2004
Discount rate		5.79	%		5.53	%		5.04	%		6.32%			5.98%			5.50%
Rate of compensation increase		4.01	%		4.00	%		4.00	%		4.14%			4.00%			4.00%
Healthcare cost trend rate		—			—			—			7.02%- 4.15%	(1)		5.89%- 3.98%	(1)		6.02%- 4.01%	(1)

Note:

(1) Reduction in average assumed healthcare trend rate occurs in period until 2009

Weighted average assumptions used to determine net periodic benefit cost for years ended December 31:

										Other Post-employment
	Pension Benefits									Benefits
	2002			2003			2004			2002			2003			2004
	%
Discount rate		6.12	%		5.79	%		5.53	%		6.68%			6.32%			5.98%
Expected long-term return on plan assets		5.75	%		8.11	%		7.98	%		n/a			n/a			n/a
Rate of compensation increase		3.21	%		4.01	%		4.00	%		3.78%			4.14%			4.00%
Healthcare cost trend rate		—			—			—			6.60%- 3.72%	(1)		7.02%- 4.15%	(1)		5.89%- 3.98%	(1)

Note:

(1) Reduction in average assumed healthcare trend rate occurs in period until 2009

     A one percentage point change in the assumed healthcare cost trend rate would have the following effect:

	One percentage		One percentage
	point increase		point decrease
	($ in millions)
Effect on service and interest cost in 2004		1		(1	)
Effect on postretirement benefit obligation at December 31, 2004		4		(4	)

      Actuarial gains and losses are amortized on a straight-line basis over current employees’ average remaining service lives.

      The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid:

			Other Post-
	Pension		employment
	Benefits		Benefits
	($ in millions)
2005		15		—
2006		10		—
2007		11		—
2008		14		—
2009		17		—
2010 - 2014		98		2

F-38

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      The pension and other post-employment benefit amounts recognized in future periods could be materially different from these amounts, principally because pension obligations relating to retired and terminated vested German employees prior to April 1, 2005, remained the responsibility of BP under the terms of the Master Reorganization Agreement.

Defined Contribution Plans

      The Company contributed to defined contribution pension plans for the three years ended December 31, 2004 as follows:

	For the year ended
	December 31,
	2002		2003		2004
	($ in millions)
Defined contribution pension expense		10		10		10

(17) Stock Based Compensation

      During the years ended December 31, 2002, 2003, and 2004, a number of Innovene employees participated in BP sponsored long term incentive plans. Under the plans, employees received various stock-based compensation awards, including stock options, restricted stock, stock opportunity grants and performance units.

      Under these plans, BP offered most of its employees the opportunity to acquire a shareholding in BP through savings-related and/or matching share plan arrangements. BP also used long-term performance plans and the granting of share options as elements of remuneration for executive directors and senior employees.

BP Share Option and Share Save Plans

      Share options were granted under the BP Share Option Plan to certain categories of employees. Subject to certain vesting requirements, the options are exercisable between the third and 10th anniversaries of the date of grant. There are no performance conditions attaching to the options granted during the year.

      Under the BP ShareSave Plan (a savings-related share option plan), employees save on a monthly basis over a three- or five-year period towards the purchase of shares at a price fixed when the option is granted. The option must be exercised within six months of maturity of the savings contract; otherwise it lapses. The plan is run in the UK and a small number of other countries.

      No compensation expense is recognized by the Company for the BP ShareSave Plan or in respect of share options granted to employees under the BP Share Option Plan. The Company has made pro forma disclosure in Note 3 of the impact on the results of operations had compensation costs attributable to awards granted to employees of the Company been determined using the fair value-based accounting method in accordance with FASB Statement No. 123, as amended.

BP ShareMatch Plan

      Under the BP ShareMatch Plan, BP matches employees’ own contributions of shares, up to a predetermined limit. The shares are then held in trust for a defined minimum period. The plan is run in the UK and in over 70 other countries.

F-39

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

Long-term Performance Plans

      During 2004, BP operated two long-term performance plans: the Executive Directors’ Incentive Plan (EDIP) for executive directors and the Long Term Performance Plan (LTPP) for senior employees. Executive directors participated in the LTPP prior to 2002 or to their appointment as an executive director, whichever was the later. Both plans are incentive schemes under which the Company may award shares to participants or fund the purchase of shares for participants if long-term targets are met. Awards were made in 2004 in respect of the 2001-2003 LTPP.

      The costs of potential future awards for both the EDIP and LTPP are accrued over the three-year performance periods of each plan and have been allocated to the Innovene statement of operations based on Innovene senior executive headcount.

      Employee Share Ownership Plans (ESOPs) have been established to acquire BP shares to satisfy any awards made to participants under the EDIP and LTPP and then to hold them for the participants during the retention period of the plan. BP provides funding to the ESOPs.

      BP’s own shares held by the ESOP have not been included in the Innovene balance sheet.

(18) Income Taxes

      Current and deferred income tax expense (benefit) consisted of the following:

		For the year ended
		December 31,
		2002		2003		2004
		($ in millions)
Income tax expense
Federal and state
	Current		—		—		—
	Deferred		—		—		(87	)
Foreign
	Current		40		41		152
	Deferred		78		49		63
Income tax expense from continuing operations			118		90		128

F-40

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      Income before income taxes consists of the following:

	Year ended
	December 31,
	2002			2003			2004
	($ in millions)
Continuing Operations
Domestic		(48	)		(51	)		(312	)
Foreign		—			(74	)		307
Net income (loss) from continuing operations		(48	)		(125	)		(5	)
Discontinued Operations
Domestic		(29	)		(25	)		(180	)
Foreign		—			—			—
Net income (loss) from discontinued operations		(29	)		(25	)		(180	)
		(77	)		(150	)		(185	)

      Income taxes reflected in owner’s equity are as follows:

	For the year ended
	December 31,
	2002			2003			2004
	($ in millions)
AOCI — minimum pension liability		(9	)		(8	)		(14	)

      Deferred income taxes result from temporary differences between the financial and tax bases of the Company’s assets and liabilities.

F-41

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      The tax effect of temporary differences giving rise to the significant components of deferred tax assets and liabilities is as follows:

		As of
		December 31,
		2003			2004
		($ in millions)
Deferred tax assets:
Net operating losses
	Foreign		80			70
	Domestic		101			169
Restructuring reserves			4			12
Other reserves			33			30
Employee benefit plans			149			190
Research and development			10			17
Other			1			8
Total deferred tax assets			378			496
Valuation allowance			(66	)		(134	)
Net deferred tax assets			312			362
Deferred tax liabilities:
Financial instruments			(61	)		(47	)
Property			(866	)		(908	)
Other reserves			(39	)		(45	)
Other			(20	)		(2	)
Total deferred tax liabilities			(986	)		(1,002	)
Net deferred tax liabilities			(674	)		(640	)
Reported as:
Deferred tax assets — non-current			167			106
Deferred tax liabilities — current			(61	)		(47	)
Deferred tax liabilities — non-current			(746	)		(699	)
Discontinued operations
Deferred tax liabilities — non-current			(34	)		—
			(674	)		(640	)

      As more fully described in Note 3, Summary of Significant Accounting Policies, Income Taxes, the Company assesses the realizability of deferred tax assets by consideration of the potential for future taxable income in the jurisdiction to which the deferred tax asset relates. Deferred tax assets in respect of operating loss carryforwards and tax credits arising in periods before those covered by these financial statements have been reduced by valuation allowances. To the extent that deferred tax expense is recognized in respect of current period increases in deferred tax liabilities during the same period in which losses are incurred, a current tax benefit is recognized to the extent of the increase in deferred tax liabilities. Any excess amounts were assessed against the ability to realize these tax benefits in the future. As a result, the Company has provided valuation allowances to the extent that it was not likely to be realized in the future.

F-42

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      The Company’s actual tax charge from continuing activity differs as follows from the expected tax charge calculated at a statutory federal income tax rate of 35% for the following periods:

	For the year ended
	December 31,
	2002			2003			2004
	($ in millions)
Expected tax charge/(benefit) at statutory tax rate		(17	)		(44	)		(2	)
State income tax		(2	)		(2	)		(15	)
Change in valuation allowances		17			30			53
Foreign tax rate differential		15			10			3
Change in fair value of Solvay put liabilities and losses		54			77			53
Charitable contribution		—			(11	)		—
Foreign currency transactions		34			47			37
Income tax rate changes		—			(7	)		(6	)
Other		17			(10	)		5
Actual income tax charge		118			90			128

      Differences between the effective and statutory tax rates arise due principally to the effects of management’s assessment of the realizability of tax loss carryforwards, the Company’s inability to determine its deferred tax asset balances in respect of operating and tax loss carryforwards for periods before those covered by these financial statements, the inability to offset carryforwards from one jurisdiction against income arising in other jurisdictions on a separate return basis, the non-deductibility of losses associated with the accounting for the Solvay put liabilities, foreign exchange rate losses on long term debt, and higher rates and currency-related items in foreign jurisdictions.

      For the periods 2002, 2003 and 2004 the Company has followed its parent’s policy to permanently reinvest the earnings of its non-U.S. operations. The Company intends to partially reinvest the earnings of its non-U.S. subsidiaries after deduction of non-U.S. income taxes, to maintain and enhance its international operations. New non-U.S. investments will generally be held from the U.S. Because non-U.S. income taxes are, on average, equal to or higher than the comparable U.S. rates, and in accordance with the U.S. foreign tax credit assumptions described in Note 3, no provision has been made for U.S. income taxes that might be payable upon repatriation of such earnings.

(19) Commitments and Contingencies

Operating Leases

      The Company is obligated under operating leases with remaining non-cancelable terms of one year or more for property, office equipment, rail cars, storage facilities and automobiles. Rental expense for these operating leases for the years ended December 31, 2002, 2003, and 2004 was $37 million, $68 million, and $89 million, respectively.

F-43

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      At December 31, 2004, future payments under non-cancelable operating leases with a remaining term greater than one-year are as follows over each of the next five years and thereafter:

	Operating Leases
	($ in millions)
2005		73
2006		49
2007		40
2008		39
2009		42
Thereafter		304
Total minimum lease payments		547
Less executory costs		(9	)
Less sub-lease receivables		(6	)
Total		532

Environmental Matters

      As at December 31, 2004, the Company had accrued $17 million which relates to environmental liability provisions for various sites.

      The Company is subject to numerous national and local environmental laws and regulations concerning its products, operations and other activities.

      These laws and regulations may require the Company to take future action to remediate the effects on the environment of prior disposal or release of chemicals or other substances by the Company or other parties. The ultimate requirement for remediation and its cost are inherently difficult to estimate. However, the estimated cost of known environmental obligations has been accrued in accordance with the Company’s accounting policies. While the amounts of future costs could be significant to the Company’s results of operations in the period in which they are recognized, Innovene does not expect these costs to have a material effect on the Company’s financial position or liquidity.

Tax Matters

      As part of the separation from BP, the Company will incur liability for stamp duty in various countries related to the transfer of assets from BP to Innovene. In the United Kingdom, liability for stamp duty land tax will be chargeable to Innovene if and when BP’s interest in the assets transferred falls below 75%. This potential future liability for stamp duty land tax in the United Kingdom and other stamp duties is estimated to be approximately $100 million to $150 million.

Committed Capital Expenditures

      Externally committed and internally authorized future capital expenditure by the Company as at December 31, 2004 amounted to $149 million.

F-44

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

(20) Subsequent Events

      In May 2005, the Company signed the previously announced transaction with NOVA Chemicals Corporation to combine their European polystyrene and expandable polystyrene (“EPS”) businesses into a joint venture named NOVA Innovene. Under the terms of the agreement, upon closing, which is expected to occur in late 2005, Innovene will contribute its polystyrene and EPS assets at Marl, Germany and Trelleborg, Sweden while NOVA will contribute four polystyrene and EPS plants located in France, the Netherlands and the United Kingdom. Each party will receive a 50% equity interest in NOVA Innovene as consideration in the exchange. In addition, Innovene has entered into an agreement which provides for put and call options for the purchase by the Company, and transfer to NOVA Innovene, of BP’s polystyrene and EPS assets and liabilities at Wingles in the first quarter of 2007. On the exercise of either a put or call option, the consideration for the transfer is the fair market value of such assets and liabilities at the time of any transfer.

      On August 10, 2005, the Company experienced a fire at one of the crackers at the Company’s Chocolate Bayou, Texas facility. The affected unit primarily produces ethylene and represents approximately 50% of the facility’s total ethylene capacity. We are continuing to assess the operational and financial impact the incident may have on our business.

(21) Financial Instruments and Derivative Contracts

      Innovene is exposed to a number of different market risks arising from the Company’s normal business activities. Market risk is the possibility that changes in currency exchange rates, interest rates, or commodity prices will adversely affect the value of the Company’s financial assets, liabilities or expected future cash flows. The Company has developed policies aimed at managing the volatility inherent in certain of these natural business exposures and, in accordance with these policies, the Company enters into various transactions using derivative financial and commodity instruments (derivatives), including conventional exchange-traded derivative instruments such as futures and option contracts, as well as non-exchange-traded instruments such as swaps, “over-the-counter” options, and forward contracts. Derivatives are contracts whose value is derived from one or more underlying financial instruments, indices, or prices that are defined in the contract.

      The Company accounts for derivatives and hedging activities in accordance with FASB Statement No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended, which requires that all derivative instruments be recorded on the balance sheet at their respective fair values.

      The purpose for which a derivative contract is used is identified at inception. To qualify as a hedge for accounting purposes, the contract must comply with established guidelines that ensure that it is effective in achieving its objective. In such circumstances where the Company designates a derivative as a hedge against changes in the value of a recognized asset or liability, the Company’s exposure to market risk created by the derivative is offset by the opposite exposure arising from the asset or liability being hedged. In other circumstances where the Company designates a derivative as a cash flow hedge of an anticipated transaction, the changes in value of the derivative are included in Other Comprehensive Income until the occurrence of the future transaction, and then are offset by the effects of the transaction being hedged in the period it occurs. In all other cases where derivatives are not designated as a hedge for accounting purposes, changes in market value give rise to realized and unrealized gains and losses, which are recognized in current period operating results. For the periods presented herein, none of the Company’s derivative instruments were designated as hedges for accounting purposes.

F-45

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      All derivative activity, whether designated as a hedge for accounting purposes or not, is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management control, meeting generally accepted industry practice and reflecting the principles of the Group of Thirty Global Derivatives Study recommendations.

      The estimated fair value of financial instruments has been determined by using available market information and appropriate valuation methodologies. The following table provides the fair values of all material derivatives instruments outstanding as at each period.

Derivative instruments fair value and notional amounts

		As of December 31,
								As of June 30,
		2002		2003		2004		2005
		($ in millions)
Foreign exchange contracts
	Purchased options		—		—		—		1
	Foreign exchange swaps		116		204		155		—
Contractual notional amounts			1,318		1,402		1,595		750

Foreign Currency Exchange Rate Risk

      BP and Innovene’s foreign exchange management policy is to minimize economic and material transactional exposures arising from currency movements against the U.S. dollar.

      Until December 31, 2004, Innovene did not separately manage these risks, with the exception of specific risks around the sterling-denominated debt, as all exposures were managed centrally by BP on a net BP Group basis. The BP Group co-ordinated the handling of foreign exchange risks centrally, by netting off naturally occurring opposite exposures wherever possible, to reduce the risks, and then dealing with any material residual foreign exchange risks.

      The Company entered into foreign exchange derivative contracts to manage the exposure related to the sterling-denominated debt as this was a specific identifiable risk. These contracts, which all have a maturity of less than one year, are not designated as hedges for financial reporting purposes and are recorded at fair value. As of December 31, 2002, 2003, and 2004, the fair value of outstanding foreign exchange derivative contracts was $116 million, $204 million, and $155 million, respectively. Settlement of the foreign exchange swaps resulted in net pre-tax gains of $16 million, $2 million, and $4 million in 2002, 2003, and 2004 respectively.

      In early 2005, the Company began separately managing its significant non-U.S. dollar economic exposures using derivative contracts that have not been designated as hedges for accounting purposes. The most significant of such exposures are the net cash flows of the Euro and Sterling related to the Company’s activities within Continental Europe and the UK. The following table provides information about the Company’s foreign currency purchased options that were negotiated at the beginning of 2005 for a premium cost of $20 million. These financial instruments are sensitive to changes in the Sterling/U.S. dollar, Euro/U.S. dollar exchange rates.

      The fair values for the foreign exchange options in the table below are based on pricing models that take into account relevant market data.

F-46

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

Purchased options

		Notional amount by
		expected maturity date								Fair value
As of June 30, 2005		2005		2006		2007		Total		Asset		Liability
Receive sterling/pay U.S. dollars
	Contract amount ($ in millions)		250		—		—		250		0.4		—
	Weighted average strike price ($)		1.9		—		—		1.9		—		—
Receive Euro/pay U.S. dollars
	Contract amount ($ in millions)		500		—		—		500		0.2		—
	Weighted average strike price ($)		1.35		—		—		1.35		—		—

      Currency options which matured during the first half of 2005 resulted in a realized loss of $4 million from inception to June 30, 2005. Changes in fair values of outstanding options account for $15 million unrealized loss.

Commodity Prices

      Within the Company’s normal business activities, Innovene is exposed to commodity prices that could adversely affect the value of the Company’s financial assets, liabilities or expected future cash flows. Commodity price trading and hedging activities have been carried out by BP’s supply and trading function. Service agreements have been negotiated in order to ensure the continuity of such activities.

      BP risk management policy with respect to commodity price risk is to manage certain short-term exposures in respect of its business activities. To this end, BP’s supply and trading function uses the full range of conventional financial and commodity derivatives available in the relevant markets. The derivative instruments used for hedging purposes do not expose the Company to market risk because the change in their market value is offset by an equal and opposite change in the market value of the asset, liability or transaction being hedged.

      A Trading Risk Management Committee has oversight of the quality of internal control in BP’s supply and trading function. Independent control functions monitor compliance with BP’s policies. The control framework includes prescribed trading limits that are reviewed regularly by senior management, daily monitoring of risk exposure using value-at-risk principles, marking trading exposures to market and stress testing to assess the exposure to potentially extreme market situations. BP’s supply and trading activities in oil, natural gas, power and financial markets are managed within a single integrated function. This function has the responsibility for ensuring high and consistent standards of control, making investments in the necessary systems, and supporting infrastructure and providing professional management oversight.

      The Company measures its market risk exposure, i.e. potential gain or loss in fair values, on its trading activity using value-at-risk techniques. These techniques are based on a variance/ covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of the end-of-day exposures, and the history of one-day price movements over the previous twelve months, together with the correlation of these price movements. The potential movement in fair values is expressed to three standard deviations, equivalent to a 99.7% confidence level. This means that, in broad terms, one would expect to see an increase or a decrease in fair values greater than the value-at-risk on only one occasion per year if the portfolio were left unchanged.

      The Company calculates value-at-risk on all instruments that are held for trading purposes and that therefore give an exposure to market risk. The value-at-risk models take account of derivative financial instruments such as interest rate forward and futures contracts and swap agreements; foreign exchange forward and futures contracts

F-47

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

and swap agreements; and oil, natural gas and power price futures and swap agreements. Financial assets and liabilities and physical crude oil and refined products that are treated as trading positions are also included in these calculations. For options a linear approximation is included in the value-at-risk models. The value-at-risk calculation for oil, natural gas and power price exposure also includes derivative commodity instruments (commodity contracts that permit settlement either by delivery of the underlying commodity or in cash), such as forward contracts.

Commodity

      The following table provides the gain and losses, excluding any costs relating to such activities, that have been recognized in the Company’s income statement due to hedging and trading activities performed by BP’s supply and trading function.

		For the year ended
		December 31,
		2002			2003		2004
		($ in millions)
Hedging
	Petrochemicals		8			12		15
	Refining		(3	)		—		1
Trading
	Petrochemicals		4			4		5
	Refining		13			—		—

(22) Geographic and Segment Information

      The Company derives its revenues, earnings and cash flows from the manufacture and sale of a wide variety of specialty and commodity chemical products and refined oil products. The Company has five reportable operating segments: Olefins and Polymers North America, Olefins and Polymers Europe, Global Derivatives, Refining, and Corporate. The major products of each reportable operating segment are as follows:

Segment	Primary Products
Olefins and Polymers North America	Ethylene, Propylene, Butadiene, Polypropylene, High Density Polyethylene, Styrene Monomer
Olefins and Polymers Europe	Ethylene, Propylene, Butadiene, Benzene, Polypropylene, Low-, Linear Low- and High-Density Polyethylene, Styrene Monomer, Polystyrene, Expandable Polystyrene, Solvents and Industrial Chemicals
Global Derivatives	Acrylonitrile, and Linear and Poly Alpha Olefins
Refining	Gasoline, Diesel, Jet Fuel, Naphtha, LPG, Gas Oil
Corporate and other	Polymers and Acrylonitrile licensing

      The BDO business has historically been included in the Global Derivatives operating segment and is included in this segment in this note.

F-48

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

      Financial information for each of the Company’s geographic regions is as follows:

										For the
	For the year ended									six months
	December 31,									ended June 30,
	2002			2003			2004			2004			2005
										(unaudited)
	($ in millions)
Revenues:
United States		3,060			3,346			4,400			1,958			2,543
United Kingdom		3,353			3,887			4,516			1,949			3,287
Germany		1,190			1,438			1,935			765			1,110
France		2,529			2,569			3,352			1,498			2,396
Belgium		430			800			999			478			373
Rest of world		1,253			1,434			2,794			1,173			1,433
Total revenues		11,815			13,474			17,996			7,821			11,142
Less discontinued operations		(39	)		(52	)		(59	)		(30	)		(11	)
Total continuing operations		11,776			13,422			17,937			7,791			11,131

	As of
	December 31,
						As of June 30,
	2003			2004		2005
						(unaudited)
	($ in millions)
Long-lived Assets(1)
United States		2,198			1,935		1,950
United Kingdom		2,501			2,528		2,279
Germany		1,000			1,113		967
France		519			705		551
Belgium		560			476		563
Rest of world		416			379		427
Total long-lived assets		7,194			7,136		6,737
Less discontinued operations		(144	)		—		—
Total continuing operations		7,050			7,136		6,737

Note:

(1)  Represents property, plant and equipment, net of accumulated depreciation

     Revenue by geographic region was determined based on the location of the manufacturing facility generating the revenues. Long-lived assets by geographic region were determined based on where these assets were physically located.

F-49

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

											For the
		For the year ended									six months
		December 31,									ended June 30,
		2002			2003			2004			2004			2005
											(unaudited)
		($ in millions)
Revenues(1):
Olefins and Polymers
	North America		2,341			2,698			3,680			1,615			2,150
	Europe		4,863			5,609			7,424			3,328			4,399
Global Derivatives			1,788			1,821			2,149			1,045			1,283
Refining			3,876			4,779			6,555			2,699			4,331
Corporate and Other			112			69			97			24			46
Eliminations			(1,165	)		(1,502	)		(1,909	)		(890	)		(1,067	)
Total revenues			11,815			13,474			17,996			7,821			11,142
Less discontinued operations			(39	)		(52	)		(59	)		(30	)		(11	)
Total continuing operations			11,776			13,422			17,937			7,791			11,131
Adjusted EBITDA(2):
Olefins and Polymers
	North America		91			171			257			77			250
	Europe		148			54			334			195			492
Global Derivatives			188			58			(16	)		34			167
Refining			44			199			410			164			436
Corporate and Other			(52	)		(26	)		(137	)		(73	)		(254	)
Total adjusted EBITDA			419			456			848			397			1,091
Add back (deduct) adjusted EBITDA from discontinued operations			23			16			21			7			(3	)
Total adjusted EBITDA from continuing operations			442			472			869			404			1,088
Reconciliation of adjusted EBITDA from continuing operations to net income (loss) from continuing operations
Interest expense			(35	)		(44	)		(49	)		(25	)		(25	)
Provision for income taxes for continuing operations			(118	)		(90	)		(128	)		(86	)		(233	)
Asset impairments			(32	)		(36	)		(280	)		—			—
Depreciation and amortization			(423	)		(517	)		(545	)		(244	)		(284	)
Net income (loss) from continuing operations			(166	)		(215	)		(133	)		49			546

Notes:

(1)	Revenues on products sold between operating segments are recorded at market prices.
(2)	Adjusted EBITDA represents income (loss) before income tax benefit (expense), adjusted for interest expense, depreciation and amortization, and asset impairments.

F-50

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

											For the
											six months
		For the year ended									ended
		December 31,									June 30,
		2002			2003			2004			2004			2005
											(unaudited)
		($ in millions)
Depreciation and Amortization:
Olefins and Polymers
	North America		95			112			116			44			60
	Europe		184			232			248			122			130
Global Derivatives			92			107			125			55			43
Refining			51			54			54			21			40
Corporate and Other			8			19			11			6			11
Total depreciation and amortization			430			524			554			248			284
Less discontinued operations			(7	)		(7	)		(9	)		(4	)		—
Total continuing operations			423			517			545			244			284
Capital Expenditures:
Olefins and Polymers
	North America		153			174			191			79			78
	Europe		261			209			164			72			103
Global Derivatives			90			47			69			24			9
Refining			58			110			117			45			23
Corporate and Other			54			18			29			—			37
Total capital expenditures			616			558			570			220			250
Less discontinued operations			(2	)		(2	)		(3	)		(2	)		—
Total continuing operations			614			556			567			218			250

F-51

INNOVENE Inc.

Notes to Combined Financial Statements — (Continued)

(Information as of June 30, 2005 and for the six months ended

June 30, 2004 and 2005 is unaudited)

		As of December 31,
								As of June 30,
		2003			2004			2005
								(unaudited)
		($ in millions)
Total Assets:
Olefins and Polymers
	North America		2,021			2,314			2,478
	Europe		5,738			6,376			5,796
Global Derivatives			1,790			1,520			1,639
Refining			1,354			1,609			2,604
Corporate and Other			553			395			330
Eliminations			—			—			(384	)
Total assets			11,456			12,214			12,463
Less discontinued operations			(178	)		(15	)		—
Total continuing operations			11,278			12,199			12,463

F-52

Goldman, Sachs & Co. Morgan Stanley

Lehman Brothers UBS Investment Bank

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

      The following table sets forth the estimated costs and expenses, other than underwriting discounts and commissions, payable in connection with the sale of common stock being registered, all of which will be paid by the Registrant:

	Amount
SEC registration fee	$	117,700
NASD filing fee		75,500
NYSE listing fee		*
Printing expenses		*
Legal fees and expenses		*
Accounting fees and expenses		*
Blue sky fees and expenses		*
Miscellaneous		*
Total		*

*  To be filed by amendment

Item 14. Indemnification of Directors and Officers

      Section 145 of the General Corporation Law of the State of Delaware provides as follows:

      “A corporation shall have the power to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interest of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the person did not act in good faith and in a manner which the person reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had reasonable cause to believe that his conduct was unlawful.

      A corporation shall have the power to indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys’ fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect to any claim, issue or matter. as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such

II-1

person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper.”

      As permitted by the Delaware General Corporation Law, the Registrant has included in its certificate of incorporation and bylaws provisions to eliminate the personal liability of its directors for monetary damages for breach of their fiduciary duties as directors, subject to certain exceptions. In addition, the Registrant’s certificate of incorporation and bylaws provide that the Registrant is required to indemnify its officers and directors under certain circumstances, including those circumstances in which indemnification would otherwise be discretionary, and the Registrant is required to advance expenses to its officers and directors as incurred in connection with proceedings against them for which they may be indemnified.

      The underwriting agreement provides that the underwriters are obligated, under certain circumstances, to indemnify directors, officers and controlling persons of the Registrant against certain liabilities, including liabilities under the Securities Act of 1933. Reference is made to the form of underwriting agreement filed as Exhibit 1.1 hereto.

      The Registrant intends to maintain directors and officers liability insurance for the benefit of its directors and officers.

Item 15. Recent Sales of Unregistered Securities

      The Registrant has not sold any securities, registered or otherwise, within the past three years, except for the shares issued upon formation to Registrant’s sole shareholder, BP.

Item 16. Exhibits and Financial Statement Schedules

(a)  Exhibits

Exhibit number			Exhibit title
	1	.1	Underwriting Agreement*
	2	.1	Amended and Restated Master Reorganisation Agreement, dated June 30, 2005, between BP p.l.c., Innovene LLC, Innovene Europe Holdings Limited and BP Chemicals East China Investments Limited
	3	.1	Form of Innovene Inc.’s Amended and Restated Certificate of Incorporation*
	3	.2	Form of Innovene Inc.’s Amended and Restated Bylaws*
	4	.1	Form of Specimen Certificate for Innovene Inc.’s Common Stock*
	5	.1	Opinion of Sullivan & Cromwell LLP*
	10	.1	Intellectual Property and Information Technology Separation Agreement, dated April 1, 2005, between certain members of the Innovene Group and BP p.l.c.*
	10	.2	U.S. Master Tax Agreement, dated as of April 1, 2005, between Innovene LLC., BP America Inc and BP p.l.c.*
	10	.3	Rest of World Master Tax Agreement, dated as of August 3, 2005 between Innovene LLC, Innovene European Holdings Limited and BP p.l.c., each signing on behalf of various BP and Innovene entities*
	10	.4	Amended and Restated Master Feedstock Sale and Purchase Agreement for Crude Oil, dated June 16, 2005, between BP Trade and Supply (Germany) GmbH and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.5	Amended and Restated Master Feedstock Sale and Purchase Agreement for Naphtha, NGL and other Feedstock volumes, dated June 16, 2005, between BP Oil International Limited and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.6	Amended and Restated Master Refined Product Sale and Purchase Agreement, dated June 16, 2005, between BP Oil International Limited and Innovene Europe Limited (formerly O&D Trading Limited)*

II-2

Exhibit number			Exhibit title
	10	.7	Master Services Agreement in relation to Refining Commercial Optimisation Services, Naphtha Commercial Optimisation Services and NGL Commercial Services and LME Plastics Hedging, dated March 31, 2005, as amended by an amendment deed, dated June 10, 2005, and an amendment deed, dated August 18, 2005, between BP Oil International Limited and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.8	Amended and Restated Master Services Agreement in relation to NGL Commercial Optimisation Services, Naphtha Commercial Optimisation Services and Benzene Commercial Optimisation Services, dated June 16, 2005, between BP North Products America Inc and Innovene USA LLC (formerly O&D USA LLC)*
	10	.9	Amended and Restated Feedstock Sale and Purchase Agreement for Naphtha and NGL, dated June 16, 2005, between BP Products North America Inc and Innovene USA LLC (formerly O&D USA LLC)*
	10	.10	Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbons Streams produced at Carson, dated April 1, 2005, between BP West Coast Products LLC and ARCO Polypropylene LLC*
	10	.11	Amended and Restated Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Texas City, Mont Belvieu, Conway and the Hobbs Fractionator, dated June 30, 2005, between BP North Products America Inc and Innovene USA LLC (formerly O&D USA LLC)*
	10	.12	Amended and Restated Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Texas City, dated June 16, 2005, between BP Amoco Chemical Company and Innovene USA LLC (formerly O&D USA LLC)*
	10	.13	Amended and Restated Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Whiting, dated June 16, 2005, between BP Products North America Inc and Innovene USA LLC (formerly O&D USA LLC)*
	10	.14	Master Refined Products Sale and Purchase Agreement in respect of the domestic sale of Refined Products at Lavéra, dated March 31, 2005 between O&D Trading Limited and BP France SA*
	10	.15	Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Cologne, dated March 31, 2005 between Deutsche BP AG and O&D Trading Limited*
	10	.16	Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Nerefco, dated March 31, 2005 between BP Oil International Limited and O&D Trading Limited*
	10	.17	Amended and Restated Agreement regarding the Use of Infrastructure at the Nerefco Facilities in Rotterdam (Nerefco Infrastructure Agreement), dated June 16, 2005, between BP Oil International Limited and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.18	Amended and Restated Agreement regarding Transportation of Naphtha through the RMR Pipeline, dated June 16, 2005, between Deutsche BP AG and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.19	Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams supplied to Grangemouth, dated March 31, 2005, between BP Exploration Operating Company Limited and O&D Trading Limited*
	10	.20	Amended and Restated Master Refined Products Sale and Purchase Agreement in respect of the domestic sale of Refined Products produced at Grangemouth, dated June 16, 2005, between Innovene Europe Limited (formerly O&D Trading Limited) and BP Oil UK Limited*
	10	.21	The Innovene “BP LTPP” Conversion Plan, dated June 23, 2005.*
	10	.22	The Innovene Incentive Plan 2005, dated June 23, 2005.*
	10	.23	The Innovene Executive Share Matching Plan, dated June 23, 2005.*
	10	.24	Change in Control Severance Agreement for Ralph Alexander*
	10	.25	Change in Control Severance Agreement for Didier Baudrand*
	10	.26	Change in Control Severance Agreement for Dennis Seith*
	10	.27	Form of Change in Control Severance Agreement for U.S. executive officers*

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Exhibit number			Exhibit title
	21	.1	Subsidiaries of Innovene Inc.*
	23	.1	Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm
	23	.2	Consent of Sullivan & Cromwell LLP (included in Exhibit 5.1)*
	24	.1	Power of Attorney**

*	To be filed by amendment.
**	Included on signature page.

     (b) Financial Statement Schedules

Schedule II — Valuation and Qualifying Accounts

Deduction from asset accounts, allowance for doubtful debt:

	Balance at			Charged to			Charged to
	beginning			costs and			other			Balance at
$m	of year			expenses			accounts	Deductions(a),(b)		end of year
	($ in millions)
Year ended December 31, 2002		(13	)		(1	)			—		(14	)
Year ended December 31, 2003		(14	)		(7	)			3		(18	)
Year ended December 31, 2004		(18	)		(7	)			3		(23	)

Notes:

(a)	Includes foreign currency translation effects
(b)	Uncollected accounts written off, net of recoveries

Item 17.     Undertakings

      The undersigned Registrant hereby undertakes:

      (1) That for purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this Registration Statement as of the time it was declared effective.

      (2) That for the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

      (3) To provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

      (4) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

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SIGNATURES

      Pursuant to the requirements of the Securities Act of 1933, as amended, Innovene Inc. has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Chicago, Illinois, on September 12, 2005.

Innovene Inc.

By:  /s/ Ralph C. Alexander

Ralph C. Alexander

President, Chief Executive Officer and Director

POWER OF ATTORNEY

      KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints each of Ralph C. Alexander, Mark Tomkins and Henry Kleeman, and each of them acting individually, as his or her true and lawful attorneys-in-fact and agents, each with full power of substitution, for the undersigned in any and all capacities, to sign any and all amendments to this Registration Statement (including post-effective amendments or any abbreviated registration statement and any amendments thereto filed pursuant to Rule 462(b) increasing the number of securities for which registration is sought), and to file the same, with all exhibits thereto and other documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents, with full power of each to act alone, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully for all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or his or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

      Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Ralph C. Alexander Ralph C. Alexander	President, Chief Executive Officer, and Director	September 12, 2005
/s/ Mark Tomkins Mark Tomkins	Chief Financial Officer	September 12, 2005
/s/ Thomas C. Muething Thomas C. Muething	Controller	September 12, 2005
/s/ Ross J. Pillari Ross J. Pillari	Chairman of the Board and Director	September 12, 2005
/s/ Stephen A. Elbert Stephen A. Elbert	Director	September 12, 2005
/s/ Stephen Riney Stephen Riney	Director	September 12, 2005
/s/ Stephen R. Winters Stephen R. Winters	Director	September 12, 2005

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EXHIBIT INDEX

Exhibit number			Exhibit title
	1	.1	Underwriting Agreement*
	2	.1	Amended and Restated Master Reorganisation Agreement, dated June 30, 2005, between BP p.l.c., Innovene LLC, Innovene Europe Holdings Limited and BP Chemicals East China Investments Limited
	3	.1	Form of Innovene Inc.’s Amended and Restated Certificate of Incorporation*
	3	.2	Form of Innovene Inc.’s Amended and Restated Bylaws*
	4	.1	Form of Specimen Certificate for Innovene Inc.’s Common Stock*
	5	.1	Opinion of Sullivan & Cromwell LLP*
	10	.1	Intellectual Property and Information Technology Separation Agreement, dated April 1, 2005, between certain members of the Innovene Group and BP p.l.c.*
	10	.2	U.S. Master Tax Agreement, dated, as of April 1, 2005, between Innovene LLC, BP America Inc and BP p.l.c.*
	10	.3	Rest of World Tax Master Agreement, dated as of August 3, 2005 between Innovene LLC, Innovene European Holdings Limited and BP p.l.c., each signing on behalf of various BP and Innovene entities*
	10	.4	Amended and Restated Master Feedstock Sale and Purchase Agreement for Crude Oil, dated June 16, 2005, between BP Trade and Supply (Germany) GmbH and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.5	Amended and Restated Master Feedstock Sale and Purchase Agreement for Naphtha, NGL and other Feedstock volumes, dated June 16, 2005, between BP Oil International Limited and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.6	Amended and Restated Master Refined Product Sale and Purchase Agreement, dated June 16, 2005, between BP Oil International Limited and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.7	Master Services Agreement in relation to Refining Commercial Optimisation Services, Naphtha Commercial Optimisation Services and NGL Commercial Services and LME Plastics Hedging, dated March 31, 2005, as amended by an amendment deed, dated June 10, 2005 and an amendment deed, dated August 18, 2005, between BP Oil International Limited and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.8	Amended and Restated Master Services Agreement in relation to NGL Commercial Optimisation Services, Naphtha Commercial Optimisation Services and Benzene Commercial Optimisation Services, dated June 16, 2005, between BP North Products America Inc and Innovene USA LLC (formerly O&D USA LLC)*
	10	.9	Amended and Restated Feedstock Sale and Purchase Agreement for Naphtha and NGL (and other feedstock volumes), dated June 16, 2005, between BP Products North America Inc and Innovene USA LLC (formerly O&D USA LLC)*
	10	.10	Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbons Streams produced at Carson, dated April 1, 2005, between BP West Coast Products LLC and ARCO Polypropylene LLC*
	10	.11	Amended and Restated Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Texas City, Mont Belvieu, Conway and the Hobbs Fractionator, dated June 30, 2005, between BP North Products America Inc and Innovene USA LLC (formerly O&D USA LLC)*
	10	.12	Amended and Restated Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Texas City, dated June 16, 2005, between BP Amoco Chemical Company and Innovene USA LLC (formerly O&D USA LLC)*
	10	.13	Amended and Restated Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Whiting, dated June 16, 2005, between BP Products North America Inc and Innovene USA LLC (formerly O&D USA LLC)*

II-6

Exhibit number			Exhibit title
	10	.14	Master Refined Products Sale and Purchase Agreement in respect of the domestic sale of Refined Products at Lavéra, dated March 31, 2005 between O&D Trading Limited and BP France SA*
	10	.15	Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Cologne, dated March 31, 2005 between Deutsche BP AG and O&D Trading Limited*
	10	.16	Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams produced at Nerefco, dated March 31, 2005 between BP Oil International Limited and O&D Trading Limited*
	10	.17	Amended and Restated Agreement regarding the Use of Infrastructure at the Nerefco Facilities in Rotterdam (Nerefco Infrastructure Agreement), dated June 16, 2005, between BP Oil International Limited and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.18	Amended and Restated Agreement regarding Transportation of Naphtha through the RMR Pipeline, dated June 16, 2005, between Deutsche BP AG and Innovene Europe Limited (formerly O&D Trading Limited)*
	10	.19	Hydrocarbons Sale and Purchase Agreement in respect of Hydrocarbon Streams supplied to Grangemouth, dated March 31, 2005, between BP Exploration Operating Company Limited and O&D Trading Limited*
	10	.20	Amended and Restated Master Refined Products Sale and Purchase Agreement in respect of the domestic sale of Refined Products produced at Grangemouth, dated June 16, 2005, between Innovene Europe Limited (formerly O&D Trading Limited) and BP Oil UK Limited*
	10	.21	The Innovene “BP LTPP” Conversion Plan, dated June 23, 2005.*
	10	.22	The Innovene Incentive Plan 2005, dated June 23, 2005.*
	10	.23	The Innovene Executive Share Matching Plan, dated June 23, 2005.*
	10	.24	Change in Control Severance Agreement for Ralph Alexander*
	10	.25	Change in Control Severance Agreement for Didier Baudrand*
	10	.26	Change in Control Severance Agreement for Dennis Seith*
	10	.27	Form of Change in Control Severance Agreement for U.S. executive officers*
	21	.1	Subsidiaries of Innovene Inc.*
	23	.1	Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm
	23	.2	Consent of Sullivan & Cromwell LLP (included in Exhibit 5.1)*
	24	.1	Power of Attorney**

* To be filed by amendment.

** Included on signature page.

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