BP p.l.c., formerly British Petroleum, is an international British petroleum company headquartered in London. Worldwide, BP had consolidated sales of $396 billion in 2012 and employed 83,900 people. The company has proven reserves of 17.0 billion barrels of oil equivalent worldwide. The company owns around 20,700 petrol stations and serves 13 million customers every day. Due to an oil spill - triggered on April 20, 2010 by the BP-operated Deepwater Horizon drilling platform in the Gulf of Mexico - the company was sentenced in 2015 by the US environmental agency USEPA to pay a record fine of $20.8 billion. A 2019 survey found that BP, with an emissions of 34.02 billion tonnes of CO2 equivalent since 1965, was the world's sixth-highest in that period.
With sales of $251.9 billion and a profit of $4.3 billion, BP ranks 36th among the world's largest companies according to Forbes Global 2000 (as of 2017). BP had a market cap of approximately $152.6 billion in early 2018.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 20-F (Mark One) [ ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g) OF THE SECURITIES EXCHANGE ACT OF 1934 OR [ X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-6262 - -------------------------------------------------------------------------------- BP AMOCO p.l.c. - -------------------------------------------------------------------------------- (Exact name of Registrant as specified in its charter) ENGLAND and WALES - -------------------------------------------------------------------------------- (Jurisdiction of incorporation or organization) Britannic House 1 Finsbury Circus London EC2M 7BA England - -------------------------------------------------------------------------------- (Address of principal executive offices) Securities registered or to be registered pursuant to Section 12(b) of the Act. Title of each class Name of each exchange on which registered Ordinary Shares of 25c each Chicago Stock Exchange* New York Stock Exchange* Pacific Exchange, Inc.* ---------------------------------- ---------------------------------- *Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission Securities registered or to be registered pursuant to Section 12(g) of the Act. None - -------------------------------------------------------------------------------- Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. None - -------------------------------------------------------------------------------- Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report. Ordinary Shares of 25c each 22,528,746,861 Cumulative First Preference Shares of (pound)1 each 7,232,838 Cumulative Second Preference Shares of (pound)1 each 5,473,414 Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No. _____ Indicate by check mark which financial statement item the Registrant has elected to follow. Item 17 _____ Item 18 X
TABLE OF CONTENTS <TABLE> <CAPTION> <S> <C> <C> <C> Page Certain Definitions........................................... 3 Part I Item 1 Identity of Directors, Senior Management and Advisors......... 5 Item 2 Offer Statistics and Expected Timetable....................... 5 Item 3 Key Information............................................... 5 Selected Financial Information........................... 5 Risk Factors............................................. 9 Forward Looking Statements............................... 10 Statements Regarding Competitive Position................ 10 Item 4 Information on the Company.................................... 11 General.................................................. 11 Segmental Information.................................... 15 Exploration and Production............................... 17 Gas and Power............................................ 34 Refining and Marketing................................... 38 Chemicals................................................ 46 Other Businesses and Corporate........................... 53 Regulation of the Group's Business....................... 54 Environmental Protection................................. 56 Property, Plants and Equipment........................... 61 Organizational Structure................................. 62 Item 5 Operating and Financial Review and Prospects.................. 63 Group Operating Results.................................. 63 Liquidity and Capital Resources.......................... 77 Item 6 Directors, Senior Management and Employees.................... 79 Directors and Senior Management.......................... 79 Compensation............................................. 81 Board Practices.......................................... 90 Employees................................................ 93 Share Ownership.......................................... 94 Item 7 Major Shareholders and Related Party Transactions............. 96 Major Shareholders....................................... 96 Related Party Transactions............................... 96 Item 8 Financial Information......................................... 96 Consolidated Statements and Other Financial Information.. 96 Significant Changes...................................... 97 Item 9 The Offer and Listing......................................... 97 Item 10 Additional Information........................................ 99 Memorandum and Articles of Association................... 99 Material Contracts....................................... 101 Exchange Controls and Other Limitations Affecting Security Holders............................ 101 Taxation................................................. 102 Documents on Display..................................... 103 Item 11 Quantitative and Qualitative Disclosures about Market Risk.. 104 Item 12 Description of Securities Other Than Equity Securities........ 109 Part II Item 13 Defaults, Dividend Arrearages and Delinquencies.............. 110 Item 14 Material Modifications to the Rights of Security Holders and Use of Proceeds...................................... 110 Item 15 Reserved...................................................... Item 16 Reserved...................................................... Part III Item 17 Financial Statements.......................................... 111 Item 18 Financial Statements.......................................... 111 Item 19 Exhibits...................................................... 111 </TABLE> 2
CERTAIN DEFINITIONS Unless the context indicates otherwise, the following terms have the meanings shown below: Oil and natural gas reserves `Proved reserves' -- Estimated quantities of crude oil or natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. `Proved developed reserves' -- Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing natural forces and mechanisms of primary recovery are included as 'proved developed reserves' only after testing by a pilot project or after the operation of an installed programme has confirmed through production response that increased recovery will be achieved. `Proved undeveloped reserves' -- Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances are estimates of proved undeveloped reserves attributable to acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Miscellaneous terms `ADR'-- American Depositary Receipt. `ADS'-- American Depositary Share. `Amoco' -- The former Amoco Corporation and its subsidiaries. 'ARCO' -- Atlantic Richfield Company and its subsidiaries. `Associated undertaking' -- An undertaking in which the BP Group has a participating interest and over whose operating and financial policy the BP Group exercises a significant influence (presumed to be the case where 20% or more of the voting rights are held) and which is not a subsidiary undertaking. `Barrel' -- 42 US gallons. `Billion'-- 1,000,000,000. `BP', `BP Group' or the `Group'-- BP Amoco p.l.c. and its subsidiaries. 'Burmah Castrol' -- Burmah Castrol plc and its subsidiaries. `Cent' or `c' -- One hundredth of the US dollar. The `Company' -- BP Amoco p.l.c. `Crude oil' -- Includes condensate and natural gas liquids. `Dollar' or `$' -- The US dollar. `FSA' -- Financial Services Authority `Gas'-- Natural Gas. `LNG'-- Liquefied Natural Gas. `London Stock Exchange' or `LSE'-- London Stock Exchange Limited. `LPG'-- Liquefied Petroleum Gas. `NGL'-- Natural Gas Liquid. 3
Noon Buying Rate' -- The noon buying rate in New York City for cable transfers in pounds as certified for customs purposes by the Federal Reserve Bank of New York. `OECD' -- Organization for Economic Cooperation and Development. `Oil' -- Crude oil, condensate and natural gas liquids. `OPEC'-- The Organization of Petroleum Exporting Countries. `Ordinary Shares'-- Ordinary fully paid shares in BP Amoco p.l.c. of 25c each. `Pence' or `p' -- One hundredth of a pound. `Pound', `sterling' or `(pound)' -- The pound sterling. `Preference Shares'-- Cumulative First Preference Shares and Cumulative Second Preference Shares in BP Amoco p.l.c. of(pound)1 each. `Subsidiary undertaking' -- An undertaking in which the BP Group holds a majority of the voting rights. `Tonne' or `metric ton' -- 2,204.6 pounds. `Trillion'-- 1,000,000,000,000. `UK'-- United Kingdom of Great Britain and Northern Ireland. `UK GAAP' -- Generally Accepted Accounting Practice in the UK. `Undertaking' -- A body corporate, partnership or an unincorporated association, carrying on a trade or business. `US' or `USA' -- United States of America. `US GAAP' -- Generally Accepted Accounting Principles in the USA. 'Vastar' -- Vastar Resources Inc. and its subsidiaries. 4
PART I ITEM 1 -- IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS Not applicable. ITEM 2 -- OFFER STATISTICS AND EXPECTED TIMETABLE Not applicable. ITEM 3 -- KEY INFORMATION SELECTED FINANCIAL INFORMATION Summary The information shown below for 2000, 1999, 1998 and 1997 has been extracted or derived from the audited financial statements of the BP Group presented elsewhere herein. The information for 1996 has been extracted from the Annual Report on Form 20-F for the year 1998 which has been filed with the Securities and Exchange Commission, as changed to conform with the accounting presentation adopted in this annual report. <TABLE> <CAPTION> Years ended December 31, (a) ----------------------------------------------- 2000 1999 1998 1997 1996 ----- ----- ----- ----- ----- ($ million except per share amounts) <S> <C> <C> <C> <C> <C> UK GAAP Income statement data Turnover................................... 161,826 101,180 83,732 108,564 102,064 Less:joint ventures........................ (13,764) (17,614) (15,428) (16,804) -- ----- ----- ----- ----- ----- Group turnover............................. 148,062 83,566 68,304 91,760 102,064 Total replacement cost operating profit (a) 17,756 8,894 6,521 10,683 10,634 Replacement cost profit before exceptional items (b).................. 11,214 5,330 3,959 6,622 6,659 Profit for the year........................ 11,870 5,008 3,220 5,673 7,417 Per ordinary share (c): (cents) Profit for the year: Basic.................................... 54.85 25.82 16.77 29.56 38.79 Diluted.................................. 54.48 25.68 16.70 29.41 38.63 Dividends (d)............................ 20.5 20.0 19.8 18.0 15.5 Average number outstanding of 25 cents ordinary shares (shares million)...... 21,638 19,386 19,192 19,185 19,119 Balance sheet data Total assets............................... 143,938 89,561 84,915 86,279 88,651 Net assets................................. 74,001 44,342 43,573 43,603 42,443 Share capital.............................. 5,653 4,892 4,863 4,330 4,382 BP shareholders' interest.................. 73,416 43,281 42,501 42,503 42,130 Finance debt due after more than one year.. 14,772 9,644 9,641 8,853 8,954 Debt to borrowed and invested capital (e).. 17% 18% 18% 17% 17% Other data Per ordinary share: (cents) Replacement cost profit before exceptional items...................... 51.82 27.48 20.62 34.51 34.82 Net cash inflow from operating activities (f) 20,416 10,290 9,586 15,558 13,679 Net cash outflow from capital expenditure acquisitions and disposals............... 6,207 5,142 6,520 10,056 8,056 </TABLE> 5
<TABLE> <CAPTION> Years ended December 31, (a) ----------------------------------------------- 2000 1999 1998 1997 1996 ----- ----- ----- ----- ----- ($ million except per share amounts) <S> <C> <C> <C> <C> <C> US GAAP Income statement data Revenues................................... 148,062 83,566 68,304 91,760 102,064 Profit for the period...................... 10,183 4,596 2,826 5,686 6,795 Comprehensive income....................... 7,674 3,674 2,848 4,106 7,218 Profit per ordinary share (c)(g): (cents) Basic.................................. 47.05 23.70 14.72 29.62 35.54 Diluted................................ 46.74 23.56 14.66 29.46 35.39 Profit per American Depositary Share (c)(g)(h): (cents) Basic.................................. 282.30 142.20 88.32 177.72 213.24 Diluted................................ 280.44 141.36 87.96 176.76 212.34 Balance sheet data Total assets............................... 152,355 90,342 85,538 87,076 89,934 BP shareholders' interest................... 65,666 37,838 37,334 37,504 37,259 Other data Net cash used in investing activities...... 6,326 4,922 6,861 10,151 8,311 Net cash used in financing activities...... 7,852 3,332 2,161 3,449 3,239 </TABLE> - ---------- (a) Operating profit is a UK GAAP measure of trading performance. It excludes profits and losses on the sale of businesses and fixed assets and fundamental restructuring costs, interest expense and taxation. BP determines operating profit on a replacement cost basis, which eliminates the effect of inventory holding gains and losses. For the oil and gas industry, the price of crude oil can vary significantly from period to period; hence the value of crude oil (and products) also varies. As a consequence, the amount that would be charged to cost of sales on a first-in, first-out (FIFO) basis of inventory valuation would include the effect of oil price fluctuations on oil and products inventories. BP therefore charges cost of sales with the average cost of supplies incurred during the period rather than the historical cost of supplies on a FIFO basis. For this purpose, inventories at the beginning and end of the period are valued at the average cost of supplies incurred during the period rather than at their historical cost. These valuations are made quarterly by each business unit, based on local oil and product price indices applicable to their specific inventory holdings, following a methodology that has been consistently applied by BP for many years. Operating profit on the replacement cost basis and a derivative measure, that is profit adjusted for depreciation and amortization arising from the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions, and adjusted for special items (non recurring charges and credits that are not classified as exceptional under UK GAAP), are used by BP management as the primary measures of business unit trading performance and BP management believes that these measures assist investors to assess BP's underlying trading performance from period to period. Replacement cost is not a US GAAP measure. The major US oil companies apply the last-in, first-out (LIFO) basis of inventory valuation. The LIFO basis is not permitted under UK GAAP. The LIFO basis eliminates the effect of price fluctuations on crude oil and product inventory except where an inventory drawdown occurs in a period. BP management believes that where inventory volumes remain constant or increase in a period, operating profit on the LIFO basis will not differ materially from operating profit on BP's replacement cost basis. Where an inventory drawdown occurs in a period, cost of sales on a LIFO basis will be charged with the historical cost of the inventory drawn down, whereas BP's replacement cost basis charges cost of sales at the average cost of supplies for the period. To the extent that the historical cost on the LIFO basis of the inventory drawn down is lower than the current cost of supplies in the period, operating profit on the LIFO basis will be greater than operating profit on BP's replacement cost basis. To the extent that the historical cost on the LIFO basis of the inventory drawdown is greater than the current cost of supplies in the period, operating profit on the LIFO basis will be lower than operating profit on BP's replacement cost basis. (b) Replacement cost profit before exceptional items excludes profits and losses on the sale of businesses and fixed assets and fundamental restructuring costs, which are defined by UK GAAP. This measure and a derivative measure, that is profit adjusted for depreciation and amortization arising from the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions, and adjusted for special items (non recurring charges and credits that are not classified as exceptional under UK GAAP), are used by the BP board in setting targets for and monitoring performance within the Group. BP's management believes these indicators provide the most relevant and useful measures for investors because they most accurately reflect underlying trading performance. 6
(c) With effect from October 4, 1999 BP split (or subdivided) its ordinary share capital. As a result, the number of Ordinary Shares held at the close of business on Friday October 1, 1999, doubled, and holders of ADSs received a two-for-one stock split. Comparative figures for 1996 to 1998 inclusive have been changed accordingly. (d) BP dividends per share represent historical dividends per share paid by The British Petroleum Company p.l.c., for 1996 to 1998 inclusive. (e) Finance debt due after more than one year, compared with such debt plus BP and minority shareholders' interests. (f) The net cash inflows from operating activities are presented in accordance with the requirements of Financial Reporting Standard No. 1 (Revised 1996) issued by the UK Accounting Standards Board. For a cash flow statement prepared on a US GAAP basis see Item 18 -- Financial Statements -- Note 43. (g) FASB Statement of Financial Accounting Standards No. 128-- 'Earnings per Share' (SFAS 128) was adopted for the accounting period ending December 31, 1997. The amounts for 1996 has been changed accordingly. (h) The Group has adopted Financial Reporting Standard No.12 `Provisions, Contingent Liabilities and Contingent Assets' with effect from January1,1999. Comparative figures for 1996 to 1998 inclusive have been changed accordingly. Exchange Rates The following table sets forth, for the periods and dates indicated, certain information concerning the Noon Buying Rate for the pound in New York City for cable transfers in pounds as certified for customs purposes by the Federal Reserve Bank of New York. This is expressed in dollars per (pound)1. <TABLE> <CAPTION> At period end Average(a) High Low ------------- ------- ---- ---- Year ended December 31, <S> <C> <C> <C> <C> 1996............................................ 1.71 1.57 1.71 1.49 1997............................................ 1.63 1.64 1.70 1.58 1998............................................ 1.66 1.66 1.72 1.61 1999 ........................................... 1.62 1.61 1.68 1.55 2000 ........................................... 1.50 1.51 1.65 1.40 Month of September 2000.................................. 1.48 1.43 1.48 1.40 October 2000.................................... 1.45 1.45 1.47 1.43 November 2000................................... 1.42 1.43 1.45 1.40 December 2000................................... 1.50 1.46 1.50 1.44 January 2001.................................... 1.46 1.48 1.50 1.46 February 2001................................... 1.44 1.45 1.48 1.44 March 2001 (through March 30)................... 1.42 1.44 1.47 1.42 </TABLE> - ---------- (a) The average of the Noon Buying Rates on the last day of each month during the calendar year, or in the case of monthly averages, the average of all days in the month. (b) The Noon Buying Rate on March 30, 2001 was $1.42 =(pound)1. 7
Dividends BP has paid dividends on its BP ordinary shares in each year since 1917. In 2000 and thereafter, dividends were, and are expected to continue to be, paid quarterly in March, June, September and December. Until their shares have been exchanged for BP ADSs, Amoco and ARCO shareholders do not have the right to receive dividends. At least until December 31, 2003, BP will announce dividends for BP ordinary shares in US dollars and state an equivalent pounds sterling dividend. Dividends on BP ordinary shares will be paid in pounds sterling and on BP ADSs in US dollars. Prior to the fourth quarterly dividend of 1998 The British Petroleum Company p.l.c. announced dividends in sterling. Foreign exchange rates may affect dividends paid. However, when setting the dividend the directors are mindful of dividend fluctuation in sterling terms. The following table shows dividends announced by the Company per ADS for each of the past five years, together with the 'refund' but before deduction of withholding taxes as described in Item 10 -- Additional Information -- Taxation. Refund means an amount equal to the tax credit available to individual shareholders resident in the UK in respect of such dividend, less a withholding tax equal to 15% of the aggregate of such tax credit and such dividend. Dividends have been translated from pounds per ADS up to and including the third quarterly dividend for 1998, and from dollars per ADS for the fourth quarterly dividend of 1998, at an exchange rate in London on the business day last preceding the day when the directors announced their intention to pay the quarterly dividends for those years. <TABLE> <CAPTION> Quarterly --------------------------------- Dividends per American Depositary Share (a)(b) First Second Third Fourth Total ------ ------ ------ ------ ------ <S> <C> <C> <C> <C> <C> 1996.......................... UK pence 15.9 18.8 18.8 19.7 73.2 US cents 23.9 28.9 30.9 32.2 115.9 Can. cents 32.6 39.8 41.3 43.5 157.2 1997.......................... UK pence 19.7 20.6 20.7 21.5 82.5 US cents 31.9 33.6 34.6 35.3 135.4 Can. cents 44.1 46.4 48.6 50.5 189.6 1998.......................... UK pence 21.5 22.5 22.5 23.0 89.5 US cents 36.0 36.5 37.5 33.4 143.4 Can. cents 51.4 55.3 57.8 50.0 214.5 1999.......................... UK pence 20.5 20.8 20.2 20.8 82.3 US cents 33.3 33.3 33.3 33.4 133.3 Can. cents 48.7 50.1 48.6 48.5 195.9 2000.......................... UK pence 21.5 22.3 24.0 24.1 91.9 US cents 33.3 33.3 35.0 35.0 136.6 Can. cents 49.7 49.8 53.6 53.2 206.3 </TABLE> - ---------- (a) With effect from June 6, 1997 the Company split existing ADSs on a two-for-one basis so that an ADS is now equivalent to six BP ordinary shares. Comparative figures for 1996 have been changed accordingly. (b) With effect from October 4, 1999 BP split (or subdivided) its ordinary share capital. As a result, the number of BP ordinary shares held at the close of business on Friday October 1, 1999, doubled, and holders of ADSs received a two-for-one stock split. Comparative figures for 1996 to 1998 inclusive have been changed accordingly. The share dividend plan, whereby holders of BP ordinary shares could elect to receive new shares (out of unissued share capital) instead of cash dividends at a rate equivalent to the sum of the net cash dividend and related tax credit, was withdrawn following the third quarterly 1998 dividend. A dividend reinvestment plan was introduced with effect from the fourth quarterly 1998 dividend, whereby holders of BP ordinary shares can elect to reinvest the net cash dividend in shares purchased on the London Stock Exchange. This plan is not available to any person resident in the USA or Canada, or in any jurisdiction outside the UK where such an offer requires compliance by the Company with any governmental or regulatory procedures or any similar formalities. A dividend reinvestment plan is, however, available for holders of ADSs through Morgan Guaranty Trust Company of New York. Future dividends will be dependent upon future earnings, the financial condition of the Group, the Risk Factors set out below, and other matters which may affect the business of the Group set out in Item 5 -- Operating and Financial Review and Prospects. 8
RISK FACTORS There is strong competition, both within the oil industry and with other industries, in supplying the fuel needs of commerce, industry and the home. The oil industry is particularly subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation or cancellation of contract rights. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities. Exploration and production require high levels of investment and have particular economic risks and opportunities. They are subject to natural hazards and other uncertainties including those relating to the physical characteristics of an oil or natural gas field. Oil prices are subject to international supply and demand. Political developments (especially in the Middle East) and the outcome of meetings of OPEC can particularly affect world oil supply and oil prices. Oil products marketing can be affected by intense competition. Refining profitability can be volatile with both oversupply and periodic supply tightness in various regional markets. Crude oil prices are generally set in dollars while sales of refined products may be in a variety of currencies. Fluctuation in exchange rates can therefore give rise to foreign exchange exposures. Sectors of the chemicals industry are also subject to fluctuations in supply and demand within the chemicals market, with consequent effect on prices and profitability, and to governmental regulation and intervention in such matters as safety and environmental controls. In addition to the adverse effect on revenues, margins and profitability from any future fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to a review for impairment of the Group's oil and natural gas properties. This review would reflect management's view of long-term oil and natural gas prices. Such a review could result in a charge for impairment which could have a significant effect on the Group's results of operations in the period in which it occurs. 9
FORWARD LOOKING STATEMENTS In order to utilize the `Safe Harbor' provisions of the United States Private Securities Litigation Reform Act of 1995, BP is providing the following cautionary statement. This document contains certain forward-looking statements with respect to the financial condition, results of operations and business of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as `anticipates' `should', `expects', `estimates', `believes' or similar expressions. In particular, among other statements, (i) certain statements in Item 4 - Information on the Company and Item 5 - Operating and Financial Review and Prospects with regard to management aims and objectives, planned expansion, investment or other projects, expected or targeted production volume, capacity or rate, the date or period in which production is scheduled or expected to come on stream or a project or action is scheduled or expected to be completed, (ii) the statements in Item 4 -- Information on the Company -- Strategy and Financial Targets with respect to the Group's ratio of net debt to net debt plus equity, dividend policy, the manner in which we use cash surpluses, the target to reduce the combined cost structure of the Group, return on average capital employed, changes in production, targeted performance improvements and effect on pre tax results, and levels of annual investment, and (iii) the statements in Item 5 - Operating and Financial Review and Prospects including the statements under `Outlook' with regard to trends in the trading environment, oil and gas prices, refining, marketing and chemicals margins, inventory and product stock levels, supply capacity, profitability, results of operation, liquidity or financial position are all forward-looking in nature. By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including the specific factors identified in the discussions accompanying such forward-looking statements; future levels of industry product supply, demand and pricing; political stability and economic growth in relevant areas of the world; development and use of new technology and successful partnering; the actions of competitors; natural disasters and other changes to business conditions; and other factors discussed elsewhere in this report. In addition to factors set forth elsewhere in this report, the factors set forth above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements. STATEMENTS REGARDING COMPETITIVE POSITION Statements made in Item 4 -- Information on the Company, referring to BP's competitive position are based on the company's belief, and in some cases rely on a range of sources, including investment analysts' reports, independent market studies and BP's internal assessment of market share based on publicly available information about the financial results and performance of market participants. 10
ITEM 4 -- INFORMATION ON THE COMPANY GENERAL Unless otherwise indicated, information in this Item reflects 100% of the assets and operations of the Company and its subsidiaries which were consolidated at the date or for the periods indicated, without the exclusion of minority interests. Also, unless otherwise indicated, figures for business turnover include sales between BP businesses. BP was created on December 31, 1998 by the merger of Amoco Corporation of the USA and The British Petroleum Company p.l.c. of the UK. Following this merger, Amoco Corporation became a wholly owned subsidiary of The British Petroleum Company p.l.c. and was renamed BP Amoco Corporation, and The British Petroleum Company p.l.c. was renamed BP Amoco p.l.c. Amoco Corporation was incorporated in Indiana, USA, in 1889 and The British Petroleum Company p.l.c. was incorporated in 1909 in England. On April 14, 2000 we acquired the Atlantic Richfield Company (ARCO) and on July 7, 2000, we completed our successful tender offer for Burmah Castrol plc of England. To signify the single entity that has successfully been created through these combinations, authority will be sought at the Annual General Meeting in April 2001, to change the name of the company to BP p.l.c. with effect from May 1,2001. BP is one of the world's leading oil companies on the basis of market capitalization and proved reserves. Our worldwide headquarters is located in London, UK. Our registered address is: BP Amoco p.l.c. Britannic House 1 Finsbury Circus London EC2M 7BA United Kingdom Tel: +44(0)20 7496 4000 Internet address: www.bp.com Business Overview Our main businesses are Exploration and Production, Gas and Power, Refining and Marketing, and Chemicals. Exploration and Production's activities include oil and natural gas exploration and field development and production (upstream activities), together with pipeline transportation and natural gas processing (midstream activities). Gas and Power activities include marketing and trading of natural gas, liquefied natural gas (LNG), natural gas liquids (NGL) and power, the development of international opportunities that monetize gas resources and involvement in select power projects. The activities of Refining and Marketing include oil supply and trading as well as refining and marketing (downstream activities). Chemicals activities include petrochemicals manufacturing and marketing. In addition, we have a solar energy business which is one of the world's largest manufacturers of photovoltaic modules and systems. The Group provides high quality technological support for all its businesses through its research and engineering activities. We have well established operations in Europe, the USA, Canada, South America, Australasia and parts of Africa. More than 70% of the Group's capital is invested in Organization for Economic Cooperation and Development (OECD) countries with approximately one half of our fixed assets located in the USA, and about one third located in the UK and the Rest of Europe. We believe that BP has a strong portfolio of assets in each of its four main businesses: - -- In Exploration and Production in the USA we have established production bases in oil in Alaska and in oil and natural gas in the Gulf of Mexico, and extensive natural gas production in the Lower 48 States. We are the largest producer of both oil and natural gas from UK fields, and we have significant exploration or production operations in several other areas including Latin America, the Caspian Sea region and Africa. - -- In Gas and Power, which has been reported as a separate business since January 1, 2000, we have established and growing marketing and trading businesses in North America (USA and Canada), the UK and Europe. Our marketing and trading activities include gas, LNG, NGL and power. Our international gas monetization activities are focused on emerging markets such as Asia Pacific. We are involved in power projects in the USA, UK and Spain. Effective January 1, 2001, BP's North American NGL business was transferred from Refining and Marketing to Gas and Power. 11
- -- In Refining and Marketing we have a strong presence in the USA. We market under the Amoco and BP brands in the Midwest, East, and Southeast, and under the ARCO brand on the West Coast. In Europe we have a strong retail position and increased our presence in 2000 by buying out ExxonMobil's interest in the BP/Mobil European fuels business. In 2000, we purchased Burmah Castrol, which significantly increased our lubricants activities throughout the world. In addition we have established or are growing businesses elsewhere in the world under the BP brand. - -- In Chemicals we have a strong manufacturing and marketing base in the USA and Europe, and are aiming to grow in the Asia Pacific region where we already have interests in a number of production facilities. We have a strong position in the technology and production of olefins and derivative products (polyethylene, acetic acid and acrylonitrile), as well as a leading position in aromatics and derivative products (purified terephthalic acid, paraxylene and metaxylene) and expect to strengthen our polymers market position during 2001 through our proposed deal with Solvay. On April 13, 2000 BP and ARCO announced that they had received clearance from the US Federal Trade Commission (FTC) for the combination of the two companies and the combination was completed on April 18, 2000. The combination has been accounted for as an acquisition under UK GAAP and as a purchase under US GAAP. The results of ARCO have been included with effect from April 14, 2000, the day following the approval by the US Federal Trade Commission of the acquisition. ARCO stockholders received for each share of ARCO common stock held as of April 17, 2000, 9.84 BP ordinary shares. Such shares were delivered in the form of BP ADSs, or at the election of the holder of ARCO common stock, BP ordinary shares. On March 15, 2000 ARCO entered into an agreement to sell its Alaskan businesses to Phillips Petroleum Company (Phillips) for approximately $6.5 billion cash subject to purchase price adjustments (and up to an additional $500 million based on the prices realized on production subsequent to December 31, 1999). Under the agreement ARCO agreed to sell all of the outstanding shares of ARCO Alaska Inc., together with certain other subsidiaries of ARCO engaged principally in the operation of ARCO's Alaskan businesses, along with certain pipeline and marine assets associated with the transport of Alaskan crude oil. The major portion of the sale closed on April 26, 2000. BP acquired Burmah Castrol on July 7, 2000 for $4.8 billion through a cash offer to shareholders of (pound)16.75 per share. The public share price on the date of announcement, March 10, 2000, was (pound)9.65. Burmah Castrol is a global marketer of specialised lubricant and chemical products and services. Burmah Castrol had operations in over 50 countries and employed some 18,000 people. We have announced our intention to sell the Burmah Castrol chemicals business. In December 1999, we agreed with ExxonMobil on the principles under which the BP/Mobil European joint venture would be dissolved in response to the conditions of the European Commission's authorization of the Exxon and Mobil merger. Under the agreement BP purchased ExxonMobil's 30% interest in the fuels business for $1.5 billion with effect from August 1, 2000. In addition, the two companies divided the assets of the lubricants business broadly in line with their equity stakes (Mobil 51%, BP 49%). This dissolution was substantially completed in 2000, thus increasing BP's share of all European markets where the fuels joint venture was active. On September 15, 2000 we acquired through ARCO, the common stock of Vastar held by minority shareholders at a price of $83 per share for a total consideration of $1.6 billion. The public share price on the date of announcement, March 16, 2000, was $71 7/16. Vastar became a wholly owned subsidiary of the Company. During 2000 BP made two strategic investments in China, one of the world's fastest growing economies. BP invested $416 million in the China Petroleum and Chemical Corporation (Sinopec) and $578 million in PetroChina in the initial public offerings of both companies. BP has a 2.2% interest in each company. Separately, BP announced plans to form joint ventures with both companies: in natural gas marketing and fuels retailing with PetroChina and in fuels and petroleum products marketing and chemicals with Sinopec. PetroChina and Sinopec are two of China's major companies in the oil and chemicals businesses. Strategy and Financial Targets Following completion of the merger between BP and Amoco on December 31, 1998 and in the context of low oil prices at the time, BP undertook a strategic and portfolio review in early 1999. This was completed in the Spring of 1999 and resulted, among other things, in the development of an asset divestment programme. The guiding principle of the strategic and portfolio review was to concentrate the combined Group's operations on areas of competitive strength and, in the upstream portfolio, to dispose of assets which would not be robustly economic on the basis of conservative assumptions about future oil and natural gas prices. Divestitures under this programme continued in 2000. 12
Our new strategy has evolved from this review and its principles. In Exploration and Production our goal is to have significant shares of the larger oil and natural gas fields where our supply costs can be fully competitive with all other producers. Our new business -- Gas and Power -- is specifically designed to extend our interests as the mix of world energy consumption shifts in favour of natural gas. In Refining and Marketing we intend to invest in the marketing areas which are growing, such as China and Poland, while focusing our refining on advantaged areas. In Chemicals we are continuing to establish a set of advantaged sites distinguished by excellence in manufacturing and close links to both the supply of resources and evolving demand growth. Our financial framework is to maintain a ratio of net debt to net debt plus equity, after adjusting equity for the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions, of around 20-30% and a dividend policy which aims to return to shareholders around 50% of our replacement cost profit before exceptional items after adjusting for special items and acquisition amortization, adjusted to mid-cycle business conditions. Special items are non-recurring charges and credits that are not classified as exceptional items under UK GAAP. Acquisition amortization refers to depreciation relating to the fixed asset revaluation adjustment and amortization of goodwill consequent upon the ARCO and Burmah Castrol acquisitions. Mid-cycle conditions are our best estimate of likely average prices and margins over the long term. If circumstances give us a larger surplus it is anticipated that cash will be used to pay down debt towards the lower end of our gearing range and/or be returned to shareholders. In July 1999, we announced targets which we aimed to achieve by the end of 2001. These excluded any impact from the acquisitions of ARCO and Burmah Castrol, which were completed in 2000. Following completion of these acquisitions, in July 2000 we revised our 2001 targets to reflect the enlarged Group. The principal impact of this revision was on our target to reduce the combined cost structure of the enlarged Group. The revised target is as follows: <TABLE> <CAPTION> Revised target 1998-2001 ------------ ($ billion) <S> <C> BP -- original target ............................. 4.0 ARCO (including ARCO savings pre acquisition)...... 1.5 Burmah Castrol..................................... 0.3 ----- Total target savings............................... 5.8 ===== Delivered by end of 2000........................... 4.9 ----- </TABLE> After adjusting for special items and acquisition amortization and the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions, the return on average capital employed in 2000 shows a five percentage point increase over our 1998 base-line return, on the basis of constant 1998 trading conditions. This compares with an original target for BP alone of a five percentage point increase over our 1998 base-line return at mid-cycle business conditions have been achieved by the end of 2001. In February 2001, we announced further specific targets for 2001 and future years. Performance improvements, which include cost savings, volume growth and portfolio changes, are expected to increase pre tax results on mid-cycle basis, adjusted for acquisition amortization and special items, by $2.0 billion in 2001 and, additionally, by $1.4 billion thereafter. We are targeting annual investment in the $12-13 billion range over the period 2001-2003. This is consistent with historic levels of investment for the enlarged group. By focusing on the better investment opportunities, this level of expenditure will permit growth investment in Exploration and Production to enable the business to achieve targeted production growth of at least 5.5% a year over the next five years (against a 2000 baseline). We expect to achieve the original 1999-2001 divestment target of $10 billion proceeds by end-2001. This excludes the FTC-mandated divestment of ARCO's Alaskan interests and certain other assets. 13
The following table summarizes the Group's turnover, results and capital expenditure for the last five years and total assets at the end of each of those years. <TABLE> <CAPTION> Years ended December 31, (a) ----------------------------------------------- 2000 1999 1998 1997 1996 ----- ----- ----- ----- ----- ($ million) <S> <C> <C> <C> <C> <C> Turnover.................................... 161,826 101,180 83,732 108,564 102,064 Less: joint ventures........................ 13,764 17,614 15,428 16,804 -- ------ ------ ------ ------ ------ Group turnover (sales to third parties)..... 148,062 83,566 68,304 91,760 102,064 Total replacement cost operating profit..... 17,756 8,894 6,521 10,683 10,634 Profit for the year*........................ 11,870 5,008 3,220 5,673 7,417 Capital expenditure and acquisitions........ 47,613(a) 7,345(b) 10,362 11,420 10,288 Total assets................................ 143,938 89,561 84,915 86,279 88,651 </TABLE> - -------- * After minority shareholders' interest (a) Capital expenditure and acquisitions for 2000 includes $27,506 million for the acquisition of ARCO and $8,936 million for other significant one-off cash investments, the details of which can be found in Item 5 -- Operating and Financial Review and Prospects -- Group Results. (b) Capital expenditure and acquisitions in 1999 reflected reduced investment following the merger of BP and Amoco. All capital expenditure and acquisitions have been financed from cash flow from operations, disposal proceeds and external financing. Information for 2000, 1999 and 1998 concerning the profits and assets attributable to the businesses and to the geographical areas in which the Group operates is set forth in Item 18 -- Financial Statements -- Note 44. The following table shows our production for the last five years and the estimated proved oil and gas reserves at the end of each of those years. <TABLE> <CAPTION> Years ended December 31, (a) ----------------------------------------------- 2000 1999 1998 1997 1996 ----- ----- ----- ----- ----- <S> <C> <C> <C> <C> <C> Total crude oil production (thousand barrels per day) (a)........................ 1,928 2,061 2,049 1,930 1,903 Total natural gas production (million cubic feet per day) (a)..................... 7,609 6,067 5,808 5,858 5,917 Total estimated net proved crude oil reserves (million barrels) (b).............. 6,508 6,535 7,304 7,612 7,325 Total estimated net proved natural gas reserves (billion cubic feet) (b)........... 41,100 33,802 31,001 30,374 30,349 </TABLE> - ---------- (a) Includes BP's share of equity-accounted entities. (b) Net proved reserves of crude oil and natural gas exclude production royalties due to others and reserves of equity-accounted entities. During 2000, 1,783 million barrels of oil and natural gas, on an oil equivalent* basis (mmboe), were added to BP's proved reserves (excluding purchases, sales and equity accounted entities), more than replacing the volume produced. In addition there were substantial volume movements corresponding to acquisitions and disposals. The acquisition of ARCO resulted in the addition of approximately 2,400 mmboe of proved oil and gas reserves offset by disposals, primarily Altura, which resulted in a reduction of over 1,500 mmboe. After allowing for production which amounted to 1,095 mmboe and purchases net of sales totalling 544 mmboe, BP's proved reserves increased to 13,594 mmboe. These proved reserves are mainly located in the USA (42%), the UK (17%) and Trinidad and Tobago (16%). - ---------- * Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels. 14
SEGMENTAL INFORMATION The following tables show turnover and replacement cost profit by business and by geographical area, for the years ended December 31, 2000, 1999 and 1998. <TABLE> <CAPTION> Years ended December 31, ------------------------------------------------------------------------------------------- Turnover (a) 2000 1999 1998 ----------------------------- ----------------------------- ---------------------------- Sales Sales to Sales Sales to Sales Sales to Total between third Total between third Total between third sales businesses parties sales businesses parties sales businesses parties ----- ---------- -------- ----- ---------- -------- ----- ---------- -------- <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> ($ million) ($ million) ($ million) By business Exploration and Production...... 30,942 16,787 14,155 19,133 10,063 9,070 16,080 8,664 7,416 Gas and Power................... 16,081 346 15,735 5,323 444 4,879 4,800 -- 4,800 Refining and Marketing.......... 112,815 5,923 106,892 62,893 2,524 60,369 48,437 1,812 46,625 Chemicals....................... 11,247 216 11,031 9,392 342 9,050 9,691 379 9,312 Other businesses and corporate.. 249 -- 249 198 -- 198 199 48 151 ------ ------ ------ ------ ------ ------ ------ ------ ------ Group turnover.................. 171,334 23,272 148,062 96,939 13,373 83,566 79,207 10,903 68,304 Share of joint venture sales ====== ====== 13,764 ====== ====== 17,614 ====== ====== 15,428 ------ ------ ------ 161,826 101,180 83,732 ====== ====== ====== By geographical area UK (b)......................... 50,400 15,970 34,430 30,223 4,406 25,817 22,510 2,848 19,622 Rest of Europe................. 21,553 2,911 18,642 5,973 641 5,332 5,823 700 5,123 USA............................ 72,884 2,629 70,255 38,786 1,381 37,405 33,160 1,215 31,945 Rest of World.................. 31,014 6,279 24,735 19,465 4,453 15,012 14,032 2,458 11,574 ------ ------ ------ ------ ------ ------ ------ ------ ------ 175,851 27,789 148,062 94,447 10,881 83,566 75,525 7,221 68,304 ====== ====== ====== ====== ====== ====== ====== ====== ====== Share of joint venture sales UK............................. 3,314 3,988 3,467 Rest of Europe................. 12,316 16,114 14,186 USA............................ 270 155 43 Rest of World.................. 686 342 305 ------ ------ ------ 16,586 20,599 18,001 Sales between areas 2,822 2,985 2,573 ------ ------ ------ 13,764 17,614 15,428 ====== ====== ====== </TABLE> - ------------ (a) Turnover to third parties is stated by origin which is not materially different from turnover by destination. Transfers between Group companies are made at market prices taking into account the volumes involved. (b) UK area includes the UK-based international activities of Refining and Marketing. 15
<TABLE> <CAPTION> Group Total Replacement replacement replacement cost profit cost cost before operating Joint Associated operating Exceptional interest Analysis of replacement cost profit profit(a) ventures undertakings profit(a) items(b) and tax ----------- -------- ------------ ---------- ----------- ---------- <S> <C> <C> <C> <C> <C> <C> <C> ($ million) Year ended December 31, 2000 By business Exploration and Production.......... 13,399 384 229 14,012 119 14,131 Gas and Power....................... 24 -- 162 186 -- 186 Refining and Marketing.............. 3,309 433 166 3,908 99 4,007 Chemicals........................... 576 (9) 193 760 (212) 548 Other businesses and corporate...... (1,152) -- 42 (1,110) 214 (896) ------ ------ ------ ------ ------ ------ 16,156 808 792 17,756 220 17,976 ====== ====== ====== ====== ====== ====== By geographical area UK (c).............................. 3,629 106 38 3,773 12 3,785 Rest of Europe...................... 1,488 264 261 2,013 (19) 1,994 USA................................. 7,006 44 246 7,296 459 7,755 Rest of World....................... 4,033 394 247 4,674 (232) 4,442 ------ ------ ------ ------ ------ ------ 16,156 808 792 17,756 220 17,976 ====== ====== ====== ====== ====== ====== Year ended December 31, 1999 By business Exploration and Production.......... 6,686 175 122 6,983 (1,111) 5,872 Gas and Power....................... 32 -- 179 211 14 225 Refining and Marketing.............. 1,337 380 123 1,840 (334) 1,506 Chemicals........................... 561 -- 125 686 (257) 429 Other businesses and corporate...... (880) -- 54 (826) (592) (1,418) ------ ------ ------ ------ ------ ------ 7,736 555 603 8,894 (2,280) 6,614 ====== ====== ====== ====== ====== ====== By geographical area UK (c).............................. 2,063 (1) 49 2,111 (237) 1,874 Rest of Europe...................... 548 381 238 1,167 (258) 909 USA................................. 2,803 13 185 3,001 (983) 2,018 Rest of World....................... 2,322 162 131 2,615 (802) 1,813 ------ ------ ------ ------ ------ ------ 7,736 555 603 8,894 (2,280) 6,614 ====== ====== ====== ====== ====== ====== Year ended December 31, 1998 By business Exploration and Production.......... 3,086 65 22 3,173 380 3,553 Gas and Power....................... (99) -- 157 58 16 74 Refining and Marketing.............. 1,712 760 92 2,564 394 2,958 Chemicals........................... 950 -- 150 1,100 43 1,143 Other businesses and corporate...... (475) -- 101 (374) 17 (357) ------ ------ ------ ------ ------ ------ 5,174 825 522 6,521 850 7,371 ====== ====== ====== ====== ====== ====== By geographical area UK (c).............................. 1,796 127 8 1,931 (39) 1,892 Rest of Europe...................... 345 633 271 1,249 106 1,355 USA................................. 2,506 31 94 2,631 511 3,142 Rest of World....................... 527 34 149 710 272 982 ------ ------ ------ ------ ------ ------ 5,174 825 522 6,521 850 7,371 ====== ====== ====== ====== ====== ====== </TABLE> - ------------ (a) Replacement cost operating profit is before inventory holding gains and losses and interest expense, which is attributable to the corporate function. Transfers between Group companies are made at market prices taking into account the volumes involved. (b) Exceptional items comprise profit or loss on the sale of businesses and fixed assets and termination of operations and in addition for 1999 include restructuring costs. (c) UK area includes the UK-based international activities of Refining and Marketing. 16
EXPLORATION AND PRODUCTION The activities of our Exploration and Production business include oil and natural gas exploration and field development and production -- the upstream activities -- as well as the management of crude oil and natural gas pipeline assets and liquefied natural gas (LNG) processing facilities -- the midstream activities. In addition to these activities, we also operate oil and gas export terminals and processing plants. We have Exploration and Production interests in 29 countries, with the main concentration in the USA and in the UK sector of the North Sea. Production during 2000 came from 23 countries. Our most significant midstream activities are in three major pipelines -- the Trans Alaska Pipeline System (BP 50%), the Forties Pipeline System in the UK sector of the North Sea (BP 100%) and the Central Area Transmission System pipeline (BP 29.5%) in the UK sector of the North Sea -- and three major LNG plants -- the Atlantic LNG plant in Trinidad (BP 34%), in Indonesia through the joint venture operating company Virginia Indonesia Co. (VICO) (BP 50%) and in Australia through our share of LNG from the North West Shelf natural gas development (BP 16.7%). <TABLE> <CAPTION> Years ended December 31, -------------------------- 2000 1999 1998 ----- ----- ----- ($ million) <S> <C> <C> <C> Turnover (a)............................................. 30,942 19,133 16,080 Total replacement cost operating profit.................. 14,012 6,983 3,173 Total assets............................................. 65,904 44,967 46,194 Capital expenditure and acquisitions..................... 6,383 4,194 6,223 ($ per barrel) Average BP oil realizations.............................. 26.63 16.74 12.06 Average West Texas Intermediate oil price................ 30.38 19.33 14.38 Average Brent oil price.................................. 28.44 17.94 12.73 ($ per thousand cubic feet) Average BP US natural gas realizations................... 3.72 2.06 1.82 Average Henry Hub gas price (b).......................... 3.90 2.27 2.20 </TABLE> - ---------- (a) Excludes BP's share of joint venture turnover of $585 million in 2000, $497 million in 1999 and $348 million in 1998. (b) Henry Hub First of Month Index. 2000 has been a year of major portfolio enhancements for BP. The acquisition of ARCO has significantly strengthened our natural gas position in the Lower 48 States in the US and south east Asia and provides complementary positions in the Permian basin in the Lower 48 States, the UK sector of the North Sea, Venezuela and China. There has been significant repositioning of the portfolio in line with expected growth in global demand for natural gas. Following the merger of BP and Amoco and the acquisition of ARCO, natural gas as a percentage of the BP portfolio has grown from 33% of total production in 1998 to 40% in 2000. Much of our natural gas focus will be based around the large established North American and the growing Far East markets. Our Exploration and Production strategy since 1998 is focused upon integration and driving efficiencies into the business. Following the consolidation period after the merger of BP and Amoco and the acquisition of ARCO, we are now repositioned for volume growth and further improved efficiencies. We plan to do this by sustaining our base resources, maximizing the value from our existing assets and growing through exploring for and developing new basins such as Gulf of Mexico deepwater. In line with this growth plan, capital expenditure in 2001 is expected to increase 24% from 2000 to $7.9 billion. Approximately 46% of this spending will be focused in North America, 13% in the UK, 11% in Latin America and 30% in the rest of the world. Sustaining our base resources and maximizing the value from our existing assets includes the following actions: - -- We seek opportunities for profitable growth in both the upstream and midstream activities, that are sustainable in the context of a fluctuating oil and natural gas price environment. This includes the use of decline management and enhanced recovery technologies to mitigate volume decline and increase recoveries in mature fields. It also includes investing in midstream activities which are relatively unaffected by oil and natural gas price movements, and using our pipeline infrastructure and natural gas facilities to secure additional revenue by transporting and processing volumes owned by other companies. 17
- -- An example of maximizing the value realized from our existing assets is our North American gas growth strategy (which includes Canada but excludes Gulf of Mexico deepwater). This strategy reflects BP's plan to grow our natural gas volumes at greater than 2% per annum. Supporting this strategy, we increased the 2000 development capital programme from $331 million in 1999 to $1,232 million in 2000. Activities driving this increased capital included the commencement of multi-year development drilling programmes which will add more than 600 wells in southern Wyoming and more than 350 wells in Colorado and New Mexico over the next five to seven years. Additionally, 2000 saw rig counts more than double in both the Gulf of Mexico shelf to 12 rigs and Oklahoma's Arkoma Basin to 13 rigs. In Canada, capital spending in 2000 increased our reserve replacement to 109% and ensured a significant land position in areas of new tight gas and coalbed methane trends, where we expect to apply our exploration and production expertise from the San Juan basin. We saw first evidence of the implementation of this strategy, after portfolio adjustments, as gas production in the fourth quarter of 2000 grew by 2% relative to the third quarter. - -- We actively manage existing producing assets to maintain and improve the net income and operating cash flow realized from our oil and natural gas production. In addition, we strive to reduce the cost and improve the efficiency of new investment projects. Significant savings have been achieved by developing closer relationships with partners, contractors and suppliers, and by agreeing with these parties common incentives to improve productivity. We also link internal compensation to operating and investment efficiency, within the parameters of BP policies towards health, safety and the environment. - -- Following the merger between BP and Amoco and the acquisition of ARCO and the Vastar minority interest, we have been able to capitalize on cost reduction opportunities where we had parallel operations, and have drawn on the best practices and experience of these four successful companies to extract further efficiencies from our operations and investment programmes. Since 1998 we have achieved $2.6 billion of cost reductions representing around 80% of the total target. - -- As well as delivering these cost synergies associated with the integration of BP, Amoco, ARCO and Vastar we continue to drive improvements into our unit costs. Unit production costs (often referred to as unit lifting costs) have decreased by 20% since 1998 to $2.50/boe in 2000. We plan to reduce unit production costs as we bring new developments on stream, which have lower unit production costs achieved through scale and/or application of advanced technologies. In addition we continue to achieve further efficiencies in our existing asset base. On the investment side, our finding and development cost/boe has decreased by 30% since 1998 to $3.29/boe, below our $3.50/boe ceiling set in 2000. The second element of our Exploration and Production strategy is to provide growth for the future by exploring for and developing new basins. We do this through focused exploration and selective development activity, as described below: - -- Our highly focused exploration programme has two strategy elements. The first focuses on areas of the world that have been relatively unexplored, where we believe substantial volumes of low cost, high value reserves remain to be found. The second element is highly selective exploration around our existing fields and infrastructure. Our principal areas of activity include Angola, Australia, Canada, Egypt, the Faeroe Islands, Kazakhstan, Norway, Trinidad and Tobago and the USA. Our Red Mango discovery in Trinidad and Tobago, is one recent successful result of our exploration growth strategy. - -- BP's deepwater position in the Gulf of Mexico and Angola will allow delivery of both near-term and continuing production growth. In 2001 we expect to begin production from Girassol in Angola as well as from Crosby, Nile and Mica in the Gulf of Mexico. In 2002 and 2003, production in our Gulf of Mexico Princess, Nakika, Horn Mountain, King and King's Peak fields is expected to start. In the subsequent years the large BP-operated fields commence production, including Crazy Horse, Holstein, Mad Dog and Atlantis in the Gulf of Mexico and Plutonio in Angola. As the oil industry's largest lease holder in the Gulf of Mexico, BP is poised to deliver this year-on-year production growth well into the next decade. The strength of our portfolio, derived from our deepwater exploration success, is coupled with contracting strategies with suppliers that reduce our costs and secure our access to drilling rigs and fabrication facilities. - -- In pursuit of the development of our upstream gas holdings in Trinidad, BP gained shareholder and government approval, in the fourth quarter of 2000, to expand the existing single train liquefied natural gas plant operated by Atlantic LNG, in which we hold a 34% interest, by an additional two trains. BP has a minimum 38% interest in the second and third trains and will supply 50% of the gas for the second train and 75% for the third train. 18
We continue to upgrade the quality of our asset portfolio by focusing investments in core areas (where we have either critical mass and/or significant competitive position) and disposing of non-strategic assets through asset swaps, purchases and sales. Since January 2000 examples of portfolio upgrading include: - -- In April 2000, we divested our non-core interest in Altura Energy Ltd (a Permian basin oil and gas production joint venture with Shell), for a total amount for BP and Shell together of $3.6 billion (BP 64%). - -- In April 2000, BP and its partners finalized an agreement to align their Alaskan interests and thereby optimize operations. In return for a reduction in its share of liquids production, BP achieved a significantly strengthened gas position (increased equity in gas cap from 13.8% to 26.5%) and immediate cost savings through its single operatorship of Prudhoe Bay. - -- In September 2000, BP announced the completion of the purchase of the publicly held minority interest in Vastar. This made possible the capture of significant synergies with BP's existing Lower 48 States gas business. BP had acquired 81.8% of Vastar through the ARCO acquisition. - -- In October 2000, Repsol-YPF acquired a 10% minority shareholder interest in BP Trinidad and Tobago Limited Liability Company (LLC). The transaction with Repsol has created a new platform for BP's future gas production growth in Trinidad by giving us access to gas markets and growth opportunities in Spain. - -- In January 2001, BP successfully monetized its 7% stake in the Russian oil company Lukoil, through a combined ADR placement (proceeds $237 million) and exchangeable bond offering (proceeds $420 million). This stake was obtained through the acquisition of ARCO. Upstream Activities Exploration The Group explores for and produces oil and natural gas under a wide range of licensing, joint venture and other contractual agreements. We may do this alone or, more frequently, with partners. BP acts as operator for many of these ventures. The Group's worldwide capital expenditure on exploration and appraisal in 2000 was $1,295 million, an increase of $447 million or 53% compared with 1999, as we incorporated the ARCO exploration assets into the BP portfolio and as we appraised the significant discoveries made during 1999. In 2000, we participated in 142 gross (65.1 net) exploration and appraisal wells in 21 countries. The principal areas of activity were Angola, Australia, Canada, Egypt, Norway, Trinidad and the USA. In 2000, we obtained upstream rights in several new tracts, which are expected to provide a foundation for continued exploration success. These include the following: - -- In Norway we were successful in the 16th Licence Round and were awarded 5 licences (12 blocks) including 4 licences as operator. Equity interests in the awarded blocks range from 25% to 100%. - -- In the Faeroes first Licence Round we were awarded all our priority blocks on a 100% equity basis. - -- In Canada we acquired a 50% interest in Parcel 6 offshore deepwater Nova Scotia. In addition, during 2000 we continued to shape and focus our portfolio following the ARCO acquisition by exiting Greece, Ireland, Italy, Peru and the Philippines and relinquishing certain exploration interests in Colombia, Denmark, Norway, Turkey and the UK. We have announced significant discoveries in Angola, Australia, Trinidad, Egypt, Kazakhstan, Norway and the USA. In most cases, reserve bookings from these fields will depend on the results of ongoing technical and commercial evaluations, including appraisal drilling. These discoveries included the following: - -- In the deepwater US Gulf of Mexico we announced a significant new discovery at Crazy Horse North (BP 75% and operator), which is adjacent to Crazy Horse, discovered in 1999. - -- In Trinidad we made two discoveries as operator, Manikin (BP 70%) and Red Mango (BP 100%). 19
- -- In Angola, we were involved in nine discoveries: Galio, Paladio, Cronia and Cobalto in Block 18 (BP 50% and operator), Mondo, Saxi and Batuque in Block 15 (BP 26.7%), and Perpetua and Jasmim in Block 17 (BP 16.7%). - -- In Norway we announced the Snadd discovery (BP 30% and operator). - -- In Australia, we participated in the Maenad and Urania natural gas discoveries (licence WA-267-P, BP 12.5%), which lie approximately 200 kilometres west of our LNG facilities. - -- In Egypt, in the Nile Delta we made two natural gas discoveries, Taurus and Taalab (BP 50%). Reserves and Production We annually review our total reserves of crude oil, condensate, natural gas liquids and natural gas to take account of production, field reassessments, the application of improved recovery techniques, the addition of new reserves from discoveries and economic factors. We also conduct selective periodic reserve reviews for individual fields. Details of our net proved reserves of crude oil, condensate, natural gas liquids and natural gas at December 31, 2000, 1999, and 1998 and reserves changes for each of the three years then ended are set out in the Supplementary Oil and Gas Information section in Item 18 -- Financial Statements. Total hydrocarbon proved reserves, on an oil equivalent basis and excluding equity-accounted entities, comprised 13,594 million barrels of oil equivalent (mmboe) at December 31, 2000, an increase of 10% versus December 31, 1999. Natural gas represents about 50% of these reserves. Reserve replacement through extensions, discoveries, revisions and improved recovery exceeded production for the seventh consecutive year with a ratio of 163%. In 2000, total additions to the Group's proved reserves (excluding purchases and sales and equity accounted entities) amounted to 1,783 mmboe: 1,064 mmboe through extensions to existing fields and discoveries of new fields, and the remaining 719 mmboe through revisions to previous estimates and the application of improved recovery techniques. The principal reserve additions were in Algeria, Trinidad, the UK and US Gulf of Mexico as follows: - -- In the Gulf of Mexico we added over 350 mmboe of oil and gas reserves, mainly from the approval of new field developments at Holstein, Horn Mountain, Nakika and King's Peak. - -- In Trinidad and Tobago, we added about 1 trillion cubic feet (tcf) of natural gas from El Diablo and North East Queen's Beach as part of the volumes to feed the sanctioned second and third trains of the Atlantic LNG plant. - -- In the UK Continental Shelf, we added almost 200 mmboe of oil and gas reserves, predominantly from improved recovery projects in Foinaven and Magnus. - -- In Algeria we added over 250 mmboe of oil and gas reserves from several fields following approval of the In Salah gas project and the In Amenas gas condensate project. In addition to the above changes, there were substantial volume movements corresponding to acquisitions and disposals. The acquisition of ARCO resulted in the addition of approximately 2,400 mmboe of proved oil and gas reserves offset by disposals, primarily of our common interest in Altura, which resulted in a reduction of over 1,500 mmboe. Our total hydrocarbon production (including equity-accounted entities) during 2000 averaged 3,240 thousand barrels of oil equivalent per day (mboe/d), an increase of 133 mboe/d, or 4.3% compared with 1999, as production declines in mature fields were more than offset by acquisitions, production start-ups and build-ups to full production. About 39% of our production was in the USA and 25% in the UK. 20
The following tables show BP's production by major field (asterisks denote fields operated by BP) for the three years 1998 to 2000, and BP's aggregate estimated net proved reserves as at December 31, 2000: Crude oil (a) <TABLE> <CAPTION> Net production -------------------- Production Field or Area Interest 2000 1999 1998 ------------- -------- ----- ----- ----- (%) (thousand barrels per day) <S> <C> <C> <C> <C> <C> Alaska (b) Prudhoe Bay* 26.3 146 202 232 Kuparuk 39.2 81 90 92 Milne Point* 100.0 40 42 43 Endicott* 67.9 21 25 30 Point McIntyre 32.2 16 25 36 Other Various 10 21 21 ------ ------ ------ Total Alaska 314 405 454 Lower 48 States onshore Altura (b) Various 36 127 122 Other Various 182 133 140 ------ ------ ------ Total Lower 48 States onshore 218 260 262 Gulf of Mexico (b) Mars 28.5 38 36 29 Troika 33.3 28 30 15 Pompano* 75.0 26 29 34 Other Various 105 44 39 ------ ------ ------ Total Gulf of Mexico 197 139 117 ------ ------ ------ Total USA 729 804 833 ------ ------ ------ UK offshore (b) ETAP Various 85 80 30 Foinaven* 72.0 64 56 51 Harding* 70.0 57 58 60 Forties* 96.1 53 66 76 Magnus* 85.0 47 48 61 Schiehallion/Loyal* Various 44 36 8 Andrew* 62.8 33 43 43 Miller* 40.0 22 30 31 Other Various 89 123 110 ------ ------ ------ Total UK offshore 494 540 470 Onshore Wytch Farm* 50.5 40 40 48 ------ ------ ------ Total UK 534 580 518 ------ ------ ------ Norway (b) Various Various 89 98 101 Netherlands Various Various 1 2 4 ------ ------ ------ Total Rest of Europe Various 90 100 105 ------ ------ ------ </TABLE> 21
<TABLE> <CAPTION> Net production -------------------- Field or Area Interest 2000 1999 1998 ------------- -------- ----- ----- ----- (%) (thousand barrels per day) <S> <C> <C> <C> <C> <C> Australia Various 16.7 37 23 30 Azerbaijan Azeri-Chirag-Gunashli* 34.1 30 32 16 Canada (b) Various Various 19 56 68 Colombia Cusiana/Cupiagua* 19.0 52 66 54 Egypt October 30.4 30 35 30 Other Various 78 95 75 Trinidad Various 100.0 47 49 47 Venezuela Various Various 46 30 31 Other (b) Various Various 51 21 34 ------ ------ ------ Total Rest of World 390 407 385 ------ ------ ------ Total Group 1,743 1,891 1,841 ====== ====== ====== Equity-accounted entities Abu Dhabi (e) Various Various 127 113 124 Argentina Various Various 40 41 45 Other Various Various 18 16 39 ------ ------ ------ Total equity-accounted entities 185 170 208 ------ ------ ------ Total Group and BP share of equity-accounted entities (d) 1,928 2,061 2,049 ====== ====== ====== </TABLE> <TABLE> <CAPTION> December 31, 2000 ------------------------------------------------------ Rest of Rest of Estimated net proved reserves (a) UK Europe USA World Total ------ ------ ------ ------ ------ (millions of barrels) <S> <C> <C> <C> <C> <C> Subsidiary undertakings Developed..................... 1,138 213 2,150 817 4,318 Undeveloped................... 254 160 1,043 733 2,190 ------ ------ ------ ------ ------ 1,392 373 3,193 1,550 6,508 ====== ====== ====== ====== ====== Equity-accounted entities 1,135 ------ Total Group and BP share of equity-accounted entities 7,643 ====== </TABLE> 22
Natural gas (a)(c) <TABLE> <CAPTION> Net production -------------------- Production Field or Area Interest 2000 1999 1998 ------------- -------- ----- ----- ----- (%) (million cubic feet per day) <S> <C> <C> <C> <C> <C> Lower 48 States onshore (b) San Juan Coal* Various 563 427 408 San Juan Conventional Various 185 129 128 Tuscaloosa Various 171 175 156 Hugoton* Various 170 162 170 Wamsutter* 70.5 100 92 87 Arkoma Various 94 111 129 Jonah* 79.1 77 57 27 Anschutz Ranch East* Various 55 67 26 Moxa Arch* 41.0 52 77 110 Whitney Canyon Various 47 52 53 Altura Various 34 118 143 Other Various 613 227 306 ------ ------ ------ Total Lower 48 States onshore 2,161 1,694 1,743 Alaska Various Various 9 10 10 Gulf of Mexico (b) Matagorda Island 623* 44.0 78 99 97 Ram Powell (VK 912) 31.0 60 72 50 Matagorda Island 519* 82.0 56 39 35 Other Various 690 361 386 ------ ------ ------ Total USA 3,054 2,275 2,321 ------ ------ ------ UK offshore (b) Bruce* 37.0 201 175 182 Marnock* 62.0 148 79 1 Braes Various 99 76 69 West Sole* 100.0 89 97 102 Viking Complex 50.0 81 107 31 Ravenspurn South* 100.0 77 87 103 Armada 18.2 75 77 74 East Leman* 48.4 58 42 71 Amethyst* 45.4 56 42 57 Vulcan 50.0 44 26 35 Britannia 9.0 41 -- -- Other Various 678 487 527 Onshore Various Various 5 6 6 ------ ------ ------ Total UK 1,652 1,301 1,258 ------ ------ ------ Netherlands P/18-2* 48.7 52 63 73 Other Various 43 48 68 Norway Various Various 41 53 59 ------ ------ ------ Total Rest of Europe 136 164 200 ------ ------ ------ Canada (b) Kirby* 71.9 69 132 139 Brazeau River Gas* 70.0 63 41 52 Ricinus* 70.0 52 54 59 Marten Hills* 96.0 47 56 56 Leismer* 54.2 32 64 49 Other Various 319 342 412 Trinidad Mahogany* 100.0 530 367 14 Immortelle* 100.0 232 207 125 Flamboyant* 100.0 69 92 187 Other 100.0 54 115 113 Australia Various 16.7 205 215 211 Sharjah Sajaa* 40.0 145 168 157 Other Various 39 38 62 Indonesia Pagerungan* 40.0 199 103 108 Sanga-Sanga 26.3 120 -- -- Other* 46.0 54 -- -- China Yacheng* 34.0 77 -- -- Other (b) Various Various 198 69 64 ------ ------ ------ Total Rest of World 2,504 2,063 1,808 ------ ------ ------ Total Group 7,346 5,803 5,587 ====== ====== ====== </TABLE> 23
Natural gas (a)(c) <TABLE> <CAPTION> Net production -------------------- Field or Area Interest 2000 1999 1998 ------------- -------- ----- ----- ----- (%) (million cubic feet per day) <S> <C> <C> <C> <C> <C> Equity-accounted entities Argentina Various Various 187 145 128 Other Various Various 76 119 93 ------ ------ ------ Total equity-accounted entities 263 264 221 ------ ------ ------ Total Group and BP share of 7,609 6,067 5,808 equity-accounted entities ====== ====== ====== </TABLE> <TABLE> <CAPTION> December 31, 2000 ------------------------------------------------------ Rest of Rest of Estimated net proved reserves (a) UK Europe USA World Total ------ ------ ------ ------ ------ (millions of cubic feet) <S> <C> <C> <C> <C> <C> Subsidiary undertakings Developed..................... 3,898 275 12,111 7,985 24,269 Undeveloped................... 1,058 71 2,400 13,302 16,831 ------ ------ ------ ------ ------ 4,956 346 14,511 21,287 41,100 ====== ====== ====== ====== ====== Equity-accounted entities 2,818 ------ Total Group and BP share of 43,918 equity-accounted entities ====== </TABLE> - ---------- (a) Net proved reserves of crude oil and natural gas, stated as of December 31, 2000, exclude production royalties due to others, and include minority interests in consolidated operations. (b) In 2000, BP acquired the interests of ARCO outside Alaska. At the same time, a deal was concluded (primarily with ExxonMobil and Phillips) in which the oil and gas interests in Prudhoe Bay (and some of the associated fields) were realigned. We also disposed of our common interest in Altura Energy. In addition to normal portfolio management in the USA and Canada, we disposed of certain of our interests in Venezuela, Colombia and the UK and acquired an interest in Pakistan as part of the Burmah Castrol acquisition. In 1999, BP sold certain interests in Canada and Venezuela. At the end of the year we purchased a significant part of Repsol-YPF's share of the assets of the dissolved Crescendo Resources partnership, a major natural gas producer and processor in Texas and Oklahoma. In 1998, BP sold its interests in Papua New Guinea, and certain interests in the USA and the UK sector of the North Sea were sold, purchased or swapped. (c) Natural gas production volumes exclude gas consumed in operations. (d) Includes NGL from processing plants in which an interest is held of 41, 54, and 67 thousand barrels per day for 2000, 1999 and 1998 respectively. (e) The BP Group holds proportionate interests, through associated undertakings, in onshore and offshore concessions in Abu Dhabi expiring in 2014 and 2018, respectively. 24
United States We are the largest producer of hydrocarbons in the USA. Our 2000 US oil production averaged 729 thousand barrels per day (mb/d). This was a decline of 9% from 1999. The acquisition of ARCO was more than offset by the disposal of our common interest in Altura Energy and realignment of Prudhoe Bay. Approximately 43% of our 2000 oil production came from Alaska, 30% from onshore Lower 48 States, and the remainder from the Gulf of Mexico. BP is the largest natural gas producer in the USA gas market. In 2000, US natural gas production was 3,054 million cubic feet per day (mmcf/d). Compared with 1999 this represents a 29% increase, of which 881 mmcf/d is due to the acquisition of ARCO. Our largest areas of growth in the USA are focused in the Gulf of Mexico and our natural gas assets onshore in the Lower 48 States. Growth in these areas is expected to more than offset the decline in our current principal oil producing fields in Alaska. In addition we have several developments either planned or under construction in Alaska to mitigate the decline and enable the region to remain a major producing area for the foreseeable future. Development expenditure in the USA (excluding pipelines) during 2000 was $2,328 million, compared with $1,212 million in 1999. In Alaska, following the realignment in Prudhoe Bay, our production of crude oil declined from 405 mb/d in 1999 to 314 mb/d in 2000. The current status of activity in Alaska is as follows: - -- In 2000 agreement was reached with the unit owners to resolve outstanding issues relating to the ownership of the Prudhoe Bay Unit (PBU) and Point Thomson Unit. The agreement aligned the respective equity interests of the owners in Prudhoe Bay Unit and provided for a single operator. The alignment results in a reduction of 63 mb/d in 2000 in our Greater Prudhoe Bay Area production, and an increased interest in Prudhoe Bay Unit gas reserves and the Point Thomson Unit. Overall the agreement is expected to facilitate optimization of operations, reduce costs significantly and facilitate new oil and gas development, for the benefit of the unit owners, the State of Alaska, and its residents. - -- Development is ongoing to mitigate the production decline at Alaska's largest producing field, Prudhoe Bay. The decline rate was reduced to 3% in 2000 and a number of near-term projects are underway for 2001. The PBU alignment has accelerated satellite development by two to three years. In 2000 there were some six wells producing from all Prudhoe Bay satellites. This will increase to over 40 by the end of 2001. Large scale facilities expansions in the form of wellpads and a pipeline will also commence in 2001. We are continuing with the infill drilling programme, a mixture of new wells, rig side-tracks and coiled tubing drilled side-tracks. We anticipate drilling some 80 new wells in Prudhoe Bay in 2001 to help sustain production levels. - -- The first phase of development of the Northstar field (BP 98% and operator) began in 1998 with module construction in Alaska. All major construction permits were received in 1999. The gravel island, where field facilities will be located, is complete, drilling has commenced, and the oil and gas pipelines have been installed. The first sealift arrived on the island during 2000, with the remaining module construction to be completed and sealifted to the island in the summer of 2001. We expect production to commence in late 2001 with a plateau rate of 50 mb/d net. Project capital expenditure for the Northstar field in 2000 was $320 million (1999 $100 million and 1998 $50 million). - -- BP sanctioned the Meltwater satellite development project at the Phillips operated Kuparuk field. The satellite is a 50 million barrel gross recoverable accumulation with first production expected by end 2001. - -- BP drilled its first viscous oil multilateral wells at the Milne Point field, yielding initial production rates above 1 mb/d. Continued development of completion technology and artificial lift is expected in 2001. - -- In line with our commitment to grow the natural gas business, recent actions taken in Alaska include the formation of a joint gas pipeline project study team (see details under Midstream Activities -- Oil and Natural Gas Transportation). - -- BP acquired the remaining 8.8% working interest in the Milne Point Unit from Occidental Petroleum as part payment for our working interest in the Bravo Dome carbon dioxide field. This acquisition takes BP's ownership of Milne Point Unit to 100%. 25
- -- The Badami oil field (BP 70% and operator) came onstream in 1998 with final project capital expenditure in that year of $120 million. It continued to produce about 2 mb/d throughout 2000. Work continues to identify additional sources of production to fill the processing facility within the Badami Unit and the surrounding area. Onshore in the Lower 48 States, BP's production of oil and gas production averaged 591 mboe/d, up from 569 mboe/d in 1999. Production comes from a large number of fields situated principally in the states of Colorado, Kansas, Louisiana, New Mexico, Oklahoma, Texas and Wyoming. Crude oil production was 218 mb/d in 2000, a reduction of 16% from 1999. This was predominantly due to the sale of our common interest in Altura Energy partly offset by production from ARCO assets in the Permian Basin. - -- In April 2000, BP and Shell sold their common interests in Altura Energy, a US onshore oil-producing joint venture, for $3.6 billion to Occidental Petroleum. - -- As part of the ARCO transaction, BP acquired certain assets located in the Permian Basin of west Texas, southeast New Mexico, and southern Colorado. The assets consist of producing properties, four plants for processing natural gas, and other miscellaneous properties and assets. Producing asset characteristics range in focus from primary production and/or development drilling to mature carbon dioxide -- and water-- flood areas. BP is one of the main producers in the Permian Basin, operating approximately 1,800 wells, with production in 2000 averaging 52 mb/d of crude oil and NGL, and 151 mmcf/d of natural gas (total production in 2000 was 78 mboe/d). - -- As an extension of producing natural gas we also processed, or caused to be processed, 120 mb/d of NGL in 2000. Prices for NGL were generally strong throughout 2000 and through utilizing our processing flexibility (either in equity plants or through third party contractual arrangements) we generated increased midstream value. Natural gas production was 2,161 mmcf/d in 2000, an increase of 21% from 1999 production, all of which is essentially due to the acquisition of ARCO. Our natural gas production in the onshore Lower 48 States is produced primarily from the following assets. - -- The southern Wyoming (Overthrust Belt, Greater Green River Basin) operations produced 374 mmcf/d of gas and 38 mb/d of liquids in 2000. Drilling activity has significantly increased in conjunction with a five year drilling programme comprising more than 600 wells, primarily in the Jonah and Wamsutter fields. The number of working rigs has increased from four to nine, and contracts have been concluded for an additional five rigs to be delivered in 2001, in anticipation of increasing production by more than 10% year on year. Colorado and New Mexico (San Juan Basin Coal and Conventional Gas Fields) operations, increased production following the acquisition of ARCO with an average production of 143 mboe/d in 2000. As a combined operation, the initial pre-work on a Coal Bed Methane infill-drilling programme was completed and the programme itself commenced in October 2000. More than 350 infill wells will be drilled in the course of this five-to-seven year long infill programme. -- In the mid-continental states (Kansas, Oklahoma, Texas and Louisiana) our natural gas production grew by 26% to 898 mmcf/d in 2000. This was due in part to the acquisition of ARCO and growth activity in line with our North American Gas strategy. Examples of increased activities are highlighted below: -- Western Kansas (Hugoton and Panoma fields) - In 2000, a well work and system optimization effort directed toward curtailing the decline in the Hugoton field resulted in arresting the decline rate to approximately half of the rate from the previous two years. That programme will be expanded to other areas of the field in 2001 in an effort to remain on the lower decline trend throughout the year. -- Oklahoma and Texas panhandles (Anadarko Basin) -- Following our buyout of these properties from the Crescendo partnership in late 1999, the number of drilling rigs had increased from three to eight by year-end 2000 with a large inventory of prospects prepared for the 2001 drilling programme. In addition, a process to model well and infrastructure performance is being implemented within the asset to improve underlying base production efficiency. -- East Texas (Cotton Valley Trend) -- Average gas production volume in 2000 of over 110 mmcf/d is expected to grow 8% in 2001. The introduction of a `smart system' in well automation has delivered a flattening in gas decline rates in Blocker Field. Further optimization of well deliquefication across five other Cotton Valley Fields is in progress. In addition, well work activity was accelerated in the second half of 2000 and progress is being made on the infill-drilling programme. 26
- -- Louisiana (Tuscaloosa Trend) -- The deepest commercial producing well in onshore Louisiana (Parlange 11) was drilled to a total depth of 23,472 feet on March 30, 2000. This well also delivered the highest daily rate from an onshore Louisiana well at 92 mmcf/d of natural gas. With these results, the Tuscaloosa trend, which was brought on stream in 1978, reached its all time highest gross production rate of 364 mmcf/d in 2000. - -- Oklahoma (Arkoma Basin) -- In 2000, we combined two of the largest producers in the Arkoma Basin, BP and Vastar. Drilling activity was increased from three rigs to six rigs and we expect to run seven rigs in 2001 as we exploit over 100 square miles of recently acquired 3-D seismic data. Rates on new wells drilled post seismic have been 1 1/2 times the pre seismic rate. - -- Gulf Coast Onshore -- In 2000, this operation was created by the combination of Vastar and BP properties in state waters of Alabama. The Vastar properties are located in three distinct geographic areas: south Texas, south Louisiana, and acres of mineral fee lands in southeast Texas. In 2000, 17 new wells were drilled, and another 60 were recompleted. In addition, two acquisitions were made, one in south Texas and one in south Louisiana, each adding approximately 2.8 mmboe in proved reserves and 1 mboe/d in net rate. In 2001, we expect production from these properties to grow by 8%. In the Gulf of Mexico, we continued our substantial year on year growth in production in 2000. Liquid production increased by over 42% from 1999 levels, averaging 197 mb/d. Gas production increased by over 55% from 1999 levels averaging 884 mmcf/d. -- Offshore Louisiana and Texas (Gulf of Mexico shelf) supplies approximately one fifth of the US natural gas market, which is the largest gas market in the world. Following the acquisition of ARCO, BP became the largest producer on the Gulf of Mexico Shelf, accounting for approximately 7% of total production. BP owns an interest in 148 fields and in 2000 produced in excess of 160 mboe/d. The Gulf of Mexico shelf is a mature basin with high decline rates, averaging 30-40% per year. In spite of that, we have maintained flat production over the last several years by utilizing advanced seismic technologies, reservoir studies, and new completion technologies. In 2000, BP and Vastar drilled a total of 97 wells with an additional 73 recompletions and workovers. Activity in the major facility hubs in the deepwater Gulf of Mexico comprised the following: - -- The successful restart of production operations on the Marlin development (BP 80% and operator) occurred following a shut-down earlier in the year to understand the cause of a systemic casing design flaw. The first well brought back on line is producing at rates exceeding 85 mmcf/d for gas and 8 mb/d for oil. Production on the facility is expected to significantly increase as additional Marlin wells continue to be brought on line through 2001. In addition, the Nile (BP 50% and operator) and King (BP 100% and operator) subsea developments are on schedule to be produced through the Marlin host platform in 2001 and 2002, respectively. Project capital expenditure for the Marlin field in 2000 was $60 million (1999 $170 million and 1998 $190 million). - -- The Pompano platform and subsea development (BP 75% and operator) successes continued in 2000 with new production coming from active well work and drilling. Expansion of the Pompano platform capacity is ongoing which will allow for the production of the Mica (BP 50%) subsea field through the host Pompano platform. The Mica development remains on track for first production in 2001. Mica will be the longest subsea oil tieback in the Gulf of Mexico to date. - -- Our active drilling and well work programme was successful in arresting field decline in the Troika field (BP 33% and operator). Gross production from the six well subsea development averaged 118 mboe/d in 2000. - -- The Europa field came onstream in 2000. Project capital expenditure in 2000 was $10 million (1999 $80 million and 1998 $20 million). Due to the continued successful development drilling results at Mars (BP 29%) and the start-up of the Europa (BP 33%) and MC 764 (BP 67%) subsea developments, the Mars facility achieved record production throughput in excess of 200 mb/d of oil and 200 mmcf/d of gas in 2000. Three new wells were drilled and completed at Mars in 2000, all of which helped to ensure the facility remained fully utilized. Additional facility expansion work was performed in 2000, with an additional phase of expansion ongoing in early 2001. - -- The Ursa development (BP 23%) which came onstream in 1999 had project capital expenditure of $30 million in 1999 (1998 $120 million). Production continued to increase in 2000 with three new high rate wells being drilled and completed. Ursa, the largest floating structure currently in the Gulf of Mexico, produced on average in excess of 80 mb/d of oil and 100 mmcf/d of gas for the year. In addition, the 180 mmboe (gross) Princess discovery was made in 2000 by the Ursa partnership on a Gulf of Mexico lease block adjacent to the Ursa unit. It is envisaged that this discovery will be produced through the Ursa Tension Leg Platform (TLP) host similar to the Crosby subsea development (BP 50%), which remains on track and on schedule for first production in late 2001. 27
- -- The Diana/Hoover (BP 33%) 300 mmboe Western Gulf of Mexico basin opening development project began operations in May of 2000. Project capital expenditure in 2000 was $80 million (1999 $180 million and 1998 $130 million). The development consists of a floating Deep-draft Caisson Vessel (DDCV) host located over the Hoover field in 4,500 feet of water. Diana, a five well subsea development, is tied back to the Hoover DDCV. The Hoover DDCV is the deepest floating production facility to-date in the Gulf of Mexico. Production rates at year-end averaged over 50 mboe/d and will continue to increase well into 2001. United Kingdom We are the largest producer of both oil and natural gas in the UK. Our 2000 UK oil production of 534 mb/d was 46 mb/d lower than in 1999. This was as a direct result of reduced capital investment levels during 1999 in line with the lower oil price environment at that time and the divestment of the Scott/Telford and Fulmar fields (14 mb/d). Our UK natural gas production increased 27% from 1,301 mmcf/d in 1999 to 1,652 mmcf/d in 2000. The integration of ARCO properties in 2000 into the regional portfolio added 303 mmcf/d of production after accounting for the disposal of the ARCO interests in Scapa, Saltire, Iona, Chanter, Claymore and Piper in May 2000. Our development expenditure in the UK (excluding pipelines) grew by 20% from $676 million in 1999 to $808 million during 2000. Significant 2000 activity included the following: - -- The Foinaven main field (BP 72% and operator) and East Foinaven field (BP 43% and operator) are situated in the deep water Atlantic Margin, west of the Shetland Islands. Production from the Foinaven main field grew to 87.5mb/d gross and the Foinaven Phase II development was sanctioned. Phase II consists of the East Foinaven development and five infill wells in the Foinaven main field. First oil from both East Foinaven and the infill wells is planned for 2001. East Foinaven is a subsea development consisting of three wells tied back to the Foinaven main field facilities. Agreements have been signed to export gas from Foinaven and East Foinaven to the Magnus field. - -- Schiehallion commenced production in 1998. Project capital expenditure in that year was $220 million. Schiehallion (BP 33.4% and operator) and Loyal (BP 50% and operator) fields are also situated in the deep water Atlantic Margin. Production from these fields grew to 120 mb/d gross (44 mb/d net) and pre-sanction commitments were made in respect of the next set of infill wells to be drilled. Agreements have been signed to export gas from these fields to the Magnus field. - -- UK Government approval was received in December 2000, for the Magnus Enhanced Oil Recovery project. Through newly laid gas pipelines, the development will link the Magnus field (BP 85% and operator) to the deepwater Atlantic Margin fields via the Sullom Voe Terminal Processing plant. Surplus gas from the Atlantic Margin fields will be injected into the Magnus reservoir and we expect to recover trapped oil which will extend field life by some ten years and enable production at a plateau level of around 60 mboe/d gross until 2006. Surplus gas will be sold to the market via existing pipelines. - -- Eastern Trough Area Project (ETAP) achieved first production in 1998. Project capital expenditure in that year was $540 million. Production reached peak levels of (130 mboe/d net) during the first quarter of 2000, and on an annual average basis was 230 mboe/d gross (115 mboe/d net). The development comprises seven initial fields -- Marnock, Machar, Mungo and Monan (BP operated) and Heron, Egret and Skua (Shell operated). We have no equity interest in the Shell-operated fields. This integrated development project includes central processing facilities over the Marnock field, a normally unmanned facility over the Mungo field and subsea facilities for the other fields linked back to the central facilities. - -- During 2000, we installed a new compression system on the Bruce field (BP 37% and operator) thus reducing the wellhead flowing pressure by 50% and ensuring that the field can maintain its capacity at 850 mmcf/d gross after seven years of production. Also during the year BHP developed the Keith oil field (BP 34.83%) using a subsea well and pipeline connected to the Bruce platform. At the end of the year the Bruce platform achieved a record production of 230 mboe/d gross owing to the impact of both projects. - -- The Harding field (BP 70% and operator) continued to produce at a plateau rate of 81 mb/d (gross). During 2000 the second satellite `North' was brought on stream at a rate of 17 mb/d (gross). This followed the successful development of the `South East' satellite in 1999. A programme of further infill drilling is planned in the central and south reservoirs during 2001 to fully exploit the oil reserves in place. - -- In the southern North Sea area, there were a number of satellite and infill wells drilled. There was one successful Indefatigable field well, and a North Davy satellite well (BP 22% and operator), which alone accessed 40bcf gross of gas. The Vixen Development (BP 50%) was completed ahead of schedule, and is producing at over 130 mmcf/d gross. During the year sanction was also given for development of the Hoton Field (BP 100%). 28
- -- Work has begun to integrate the two terminals at Dimlington and Easington (BP 100% and operator). The $21-million Terminal Optimization Project will deliver environmental and safety improvements that will be required within the next 18 months. Similar safety and environmental improvements have been undertaken with the Renewal Project at the Bacton Terminal (BP 42% and operator). - -- Our southern North Sea operations have successfully integrated the ARCO properties that are being retained. We completed the European Commission mandated sale of the ARCO Thames and Murdoch field interests in April 2001. - -- Production from the Shearwater gas development (BP 28%) has been delayed owing to a potential well design problem, which is being investigated. Rest of Europe Our Norwegian production declined from 108 mboe/d in 1999 to 95 mboe/d in 2000, with natural field declines offset in part by production from drilling programs begun during the year. Net production was 37 mboe/d from Draugen (BP 18.4%), 27 mboe/d from Valhall (BP 28.1% and operator), 16 mboe/d from Ula (BP 80% and operator) and 15 mboe/d from Gyda (BP 56% and operator). In the Netherlands, our net natural gas production decreased to 95 mmcf/d from 111 mmcf/d in 1999 but will be increased to exceed 100 mmcf/d in 2001. BP is continuing to expand its role in natural gas storage services with the production and downstream gas marketing businesses working in close co-operation on this. The Peak Gas Installation expansion came onstream in 2000 increasing capacity by 50% to 1,270 mmcf/d with the potential for further capacity increase. Rest of World The Group's net share of oil production from the Rest of World decreased from 407 mb/d in 1999 to 390 mb/d in 2000. This excluded 185 mb/d from associated undertakings in 2000, of which 127 mb/d came from Abu Dhabi, where we have equity interests of 9.5% and 14.7% in onshore and offshore concessions expiring in 2014 and 2018, respectively. Other areas of oil production in 2000 were Australia, Argentina, Azerbaijan, Bolivia, Canada, China, Colombia, Egypt, Indonesia, Pakistan, Qatar, Russia, Sharjah, Trinidad and Venezuela. Our share of natural gas production from the Rest of World increased 21% from 1999, averaging 2,504 mmcf/d in 2000. In addition, in 2000 production from associated undertakings remained the same as in 1999 at 263 mmcf/d. The largest part of the 2000 production came from Trinidad and Tobago and Indonesia, with the remainder from Argentina, Australia, Bolivia, Canada, China, Colombia, Egypt, Pakistan and Sharjah. Development expenditure in the Rest of World (excluding pipelines) amounted to $1,274 million in 2000, compared with $956 million in 1999. In Canada overall production was 119 mboe/d, of which almost 85 %, 582 mmcf/d, was gas production. Development activities within Canada focused on opportunities to develop and expand within our existing core operating areas in the provinces of Alberta and British Columbia. During 2000 we drilled over 200 wells (gross), and added 49 mmboe of proved reserves. This more than replaced our 44 mmboe of production during the year. Significant activities include: - -- We acquired 169,000 acres of new mineral rights in the Western Canadian sedimentary basin during 2000. - -- Two major fields (Brazeau P-Pool and RCU #1) were converted from gas cycling schemes to full production during 2000. - -- Significant development drilling activity continued in our Kaybob, Pine Creek, Bigstone, Windfall, Wapiti, Marten Hills, St. Lina and Kirby/Leismer production areas. - -- Infrastructure is being built to bring significant new discoveries at Weejay/Ojay in north east British Columbia on stream by late 2001. - -- Currently we are pursuing opportunities to develop tight gas reservoirs and coal bed methane, and completed the first four wells in our tight gas programme in the latter part of 2000. 29
Significant activity in South America in 2000 included the following: - -- In Trinidad and Tobago, we hold a 100% interest in 121 tax and royalty licences. We also have a 70% interest in the block 5b production sharing contract. In October 2000, Repsol-YPF acquired a 10% minority shareholder interest in the BP Trinidad and Tobago LLC. The transaction with Repsol has created a new platform for BP's future gas growth in Trinidad by leveraging our upstream position in Trinidad for access to gas markets and growth opportunities in Spain. In addition, the transaction delivers opportunities to participate with Repsol-YPF in downstream gas and power joint ventures in Spain. Our Trinidad operations are in a transition from primarily oil to a balance of oil and natural gas activities with total BP hydrocarbon production during 2000 averaging 199 mboe/d net, an increase of 16 mboe/d from 1999. In 2000, gas production increased by 13% to 884 mmcf/d net, a result of increased demand due to the first full year of production from the Atlantic LNG plant operations. Drilling activity continued in the Mahogany field to develop additional natural gas and commenced in the Amherstia field with first gas production on line in the fourth quarter of 2000. This field will provide additional gas volumes to the Trinidad and Tobago market. - -- In Venezuela, in 2000 BP produced 46 mboe/d and high graded the portfolio from twelve assets to four core assets during the year. These four core assets are reactivation projects consisting of two operated properties and two non-operated properties under operating fee agreements to produce oil for the government oil company, PDVSA. In terms of acreage and production of lighter oils, BP remains the largest private oil company in Venezuela. - -- In Colombia, the development of the Cusiana/Cupiagua complex is nearing completion with the fields beginning to come off plateau. Production in 2000 was 52 mb/d net. Projects are underway to mitigate this natural decline -- these projects consist of Recetor, northern extension of Cupiagua, with Phase One granted commerciality and sanctioned during the year; an Early Production Scheme for Florena field was approved and on Niscota where an exploration contract was signed. Also during the year the rationalization of the portfolio was completed by the disposal of former Amoco and ARCO properties. - -- Through BP's equity-accounted investments in Empresa Petrolera Chaco S.A., (Chaco) (BP interest 30%) and our joint venture in Pan American Energy (PAE) (BP interest 60%) we are the second largest energy producer in the Southern Cone of South America after Repsol-YPF. In 2000, these entities produced 43 mb/d of oil and 210 mmcf/d of natural gas (net to BP) in Argentina and Bolivia. Chaco and PAE also have significant interests in natural gas liquids plants, oil and gas pipelines, electricity generation plants, and other midstream infrastructure. - -- In Argentina, a substantial gas expansion programme commenced in Gulfo San Jorge (BP 60%), complementing the oil production there, and a new plant was commissioned in the second quarter of 2000. In Northwest Argentina, new gas facilities in Acambuco (BP share 31.2%) were close to completion, with first sales due to commence in the first quarter of 2001. The construction of the Cruz del Sur pipeline (BP 18%) from Buenos Aires to Montevideo started near the end of 2000. This project will supply the Uruguyan market initially and is intended to be the first step to gaining access to the south east Brazilian market. Significant 2000 activity in Africa and the Middle East included the following: - -- In February 2000, BP and the Algerian state company, Sonatrach, agreed to go ahead with the development of seven gas fields in southern Algeria (BP 39%). The $2.5 billion development, known as the In Salah development, will supply the fast growing markets of southern Europe with some 320 billion cubic feet (bcf) annually. First deliveries are expected by 2003. The In Amenas contract between BP and Sonatrach became effective in August 1999. The project consists of the development of a wet gas field in south east Algeria and requires the construction of a 700 mmcf/d gas processing plant with associated gas, LPG and condensate export lines to tie into the existing Sonatrach transportation system. As part of the ARCO acquisition, BP acquired a 60% interest in a production sharing contract (PSC) with Sonatrach to implement an enhanced oil recovery (EOR) project on the Rhourde el Baguel field in eastern Algeria. The EOR project targets the recovery of an additional 500 mmb over the 25-year contract life. In 2000, prior to the ARCO acquisition, ARCO concluded a farmout of 40% of its interest to a wholly owned subsidiary of Sonatrach. The EOR project is in its first year of operation with gas injection facilities complete. 30
- -- In Angola, the Girassol project has made good progress and is on track to produce first oil in the fourth quarter of 2001. Other non-operated activities include appraisal drilling and engineering studies for the large-scale Kizomba (Block 15 BP 27%), Dalia and Rosa (Block 17, BP 17%) developments. In the BP operated Block 18, the Greater Plutonio discoveries have confirmed the area as a major development prospect and a team is now in place to pursue development approval over the next 12-18 months. - -- In Egypt, our operations are carried out by the Gulf of Suez Petroleum Company (Gupco), a joint operating company with the Egyptian General Petroleum Company (EGPC). Gupco operates seven production sharing contracts in the Gulf of Suez and Western Desert, encompassing more than forty fields. During 2000, Gupco produced almost 220 mb/d (107 mb/d net), about 29% percent of Egypt's oil production, as well as 78 mmcf/d (37 mmcf/d net) of natural gas. In 1999, BP finalized an agreement with the Egyptian Government, which will help maintain investment in the country's mature Gulf of Suez oil fields. Under this agreement, BP will invest $450 million by 2005 to develop new reserves, maintain production, and prolong the life of the fields. Over $126 million of this spending had been completed by year-end 2000. - -- BP entered the Nile Delta in the early 1990's, in a variety of partnerships with AGIP, EGPC and others. The Ha'py and Baltim fields were brought on stream in early 2000 and the Temsah natural gas field is expected to start-up in early 2001. Collectively, we have agreements in place to supply 332 mmcf/d to the domestic Egyptian market from these and other Nile Delta fields. BP is the second largest acreage holder in the Nile Delta and has an active exploration programme to continue to grow this reserve base. In March 2001, BP, ENI and the Egyptian General Petroleum Company entered into an agreement providing for the building of a Liquefied Natural Gas (LNG) facility at the port of Damietta. Under the agreement BP and ENI will be the sole buyers of the LNG for subsequent sale into the Mediterranean markets. First delivery to market is scheduled for the second half of 2004. - -- In Iran, we are carrying out studies and appraisals in a number of areas including Ahwaz, south Pars and LNG. Depending on the outcome of the studies and appraisals, we may in future decide to make significant investments in Iran; however, we are not currently committed to any such significant investments. Significant 2000 activity in Asia (including the former Soviet Union) included the following: - -- BP, as operator of the Azerbaijan International Operating Company (AIOC), manages and has 34.1% interest in the Azeri-Chirag-Gunashli (ACG) oil fields in the Caspian Sea, offshore Azerbaijan. In 2000 ACG production exceeded 100 mb/d gross from the Chirag 1 platform. This is expected to increase to a plateau of over 120 mb/d by 2002 following sanction of an extended reached drilling programme in 2000. Several additional phases of development are planned. Detailed engineering work is in progress for the development of the central Azeri field. - -- In Indonesia BP is now the largest supplier of natural gas to Java. Our Indonesian production in 2000 was 13 mb/d of liquids, 262 mmcf/d of gas sold to the Bontang LNG plant and 154 mmcf/d sold domestically in Indonesia. Under the terms of the production sharing contract (PSC), reported production entitlement varies inversely with price in respect of costs being recovered which are fixed in $ terms; as prices decrease therefore, a higher entitlement is received. In 2000, adjusting the reported production to a mid-cycle price of $16 would have increased the reported production by 4 mboe/d. We operate the Wiriagar and Berau block fields in Irian Jaya that will provide the largest share of the gas feed to the Tangguh LNG project. In addition, the VICO (100% equally held by BP and Lasmo) operated Sanga Sanga PSC provides 30% of the gas feed into the Bontang LNG operation for export. - -- In China, we operate both the Yacheng-13 natural gas field and the Liu Hua Oil field, and are planning to commence production from the QHD field in the fourth quarter of 2001 (operated by CNOOC). Yacheng supplies 100% of the gas supply into Hong Kong Island where it is sold to Castle Peak Power Company (CAPCO) in a long-term contract. Excess gas and liquids are piped to Hainan Island where the gas is sold to the Fuel and Chemical Company of Hainan under a long-term contract. BP's Hedong Coal Bed Methane (CBM) project (BP 70% and operator) is located in the Ordos Basin Shanxii province, approximately 800km southwest of Beijing. BP has signed three production sharing agreements covering approximately 5,200 square kilometres. BP has drilled nine wells to date and currently has a five well pilot project on production. This is BP's first CBM project in China. BP (70% and operator) is partnered with Texaco and China United Coal Bed Methane Company (CUCBM), with CUCBM having the option to take a 51% interest after determination of commerciality, with the interests of BP and Texaco to be reduced proportionately. 31
- -- In Vietnam, BP (26.7% and consortium leader) and partners had signed key elements of a $1.3 billion integrated gas project by the end of 2000 which will trigger construction of the Block 06.1 gas development and associated infrastructure in early 2001. This scheme will provide the basis for clean, reliable gas-fired power generation in southern Vietnam. First gas is planned for late 2002. - -- BP has a 10% equity interest (20% voting interest) in the Russian integrated oil company A O Sidanco (Sidanco). Sidanco was released from bankruptcy in January 2000 following repayment of all of its debts to its creditors. As of December 31, 2000 it was debt free and generating a profit. Midstream Activities Oil and Natural Gas Transportation The Group has direct or indirect interests in certain crude oil transportation systems, the principal ones of which are the Trans Alaska Pipeline System in the USA and the Forties Pipelines System in the UK sector of the North Sea. We also operate and have an interest in the Central Area Transmission System for natural gas in the UK sector of the North Sea. Our onshore US crude and product pipelines and related transportation assets are included under Refining and Marketing. Our gas marketing business is described under Gas and Power. - -- The Trans Alaska Pipeline System (TAPS) consists of a 48-inch diameter crude oil pipeline running approximately 1,300 kilometres from Prudhoe Bay to a tank farm and marine terminal at the ice-free port of Valdez on Alaska's southern coast. Alyeska Pipeline Service Company operates the pipeline and terminal at Valdez. BP owns a 50% interest in TAPS, with the balance owned by six other companies. Each of the TAPS participants uses its undivided interest in TAPS as a common carrier, separately publishing tariffs and receiving tenders for shipments through its share in the capacity of TAPS, and paying its respective share of operating costs. At peak throughput, the TAPS system carried around 2 mmb/d. In 2000, TAPS transported production from Prudhoe Bay and the other North Slope fields averaging 1 mmb/d. For a description of the procedures relating to the tariffs to be charged to users of TAPS and a general description of pipeline regulation, see Regulation of the Group's Business -- United States. There are a number of unresolved protests with regard to the yearly tariffs which are filed and which set out the charges for shipping oil through TAPS. These items are in the process of resolution at the Federal Energy Regulatory Commission (FERC) and the Regulatory Commission of Alaska. US law dictates that only ships built and flagged in the US, and operated by US citizens, may transport cargoes between ports in the USA. Hence, BP has a chartered fleet of US-flagged tankers, all operated by Alaska Tanker Company, to transport Alaskan crude oil. BP Oil Shipping Company, USA also has entered into a contract for the construction new US built, double hulled tankers to replace Alaska Tanker Company tankers not having double hulls. The contract delivery dates of the new tankers will facilitate removal of the non-double hulled tankers from the US oil tanker trade ahead of deadlines imposed by the Oil Pollution Act of 1990. For discussion of the Oil Pollution Act of 1990, see Information on the Company -- Environmental Protection. - -- The Forties Pipeline System in the UK (BP 100%) is an integrated oil and natural gas liquids transportation and processing system that handles production from over 20 fields in the central North Sea. The system was upgraded in 1993 and has a capacity of more than 1 mmb/d. During 2000, average throughput was approximately 804 mb/d, compared with 943 mb/d in 1999. Substantial reductions in Volatile Organic Compound emissions have been achieved in 2000 following the completion of the Marine Vapour recovery system in 1999. - -- BP operates and has a 29.5% interest in the Central Area Transmission System (CATS), a 400-kilometre natural gas pipeline system in the central UK sector of the North Sea. The pipeline has a transportation capacity of 1.7 billion cubic feet per day (bcf/d). It carries both proprietary and other companies' gas volumes to a natural gas terminal at Teesside, North East England. CATS offers its customers the choice of gas transportation services or transportation and processing via two 600 mmcf/d processing trains with the capability to deliver NGL for export or for local industry with gas entering the UK National Transportation System. In 2000 CATS handled throughput of 1.5 bcf/d. 32
- -- BP, as AIOC operator, manages and has 34.1% interest in the Western Export Route Pipeline between Sangachal, which is near Baku in Azerbaijan, and Supsa on the Black Sea coast of Georgia. AIOC also operates the Azeri leg of the Northern Export Route Pipeline between Sangachal and Novorossiysk in Russia. The combined capacity of the pipelines is in excess of 200 mb/d. Negotiations with transit countries for the development of an additional export pipeline with a capacity of 1 mmb/d from Sangachal to Ceyhan on the Turkish Mediterranean coast were progressed. Transit agreements were completed with the governments of Azerbaijan, Georgia, and Turkey to support implementation of a 1 mmb/d pipeline from Baku to Ceyhan on the Turkish Mediterranean coast. Based on these agreements in October 2000, BP along with seven partners formed a consortium to promote development of the Baku-Tbilisi-Ceyhan (BTC) pipeline as the key long-term export route for oil from Azerbaijan. The additional export capacity provided would be expected to be largely taken by future production from ACG and other Azerbaijan developments. - -- In Alaska agreement was reached among the major North Slope gas resource owners (BP, ExxonMobil and Phillips) to form a joint gas pipeline project study team, headquartered in Anchorage. The key programme activities in 2001 will be conceptual design, project costing, permitting considerations, commercial structure, and overall viability. The focus will be on route evaluation and selection leading to a filing of applications with US and Canadian regulatory agencies. Construction was initiated on an $86 million gas-to-liquids demonstration unit, located in Nikiski, Alaska. This plant will utilize BP's compact reformer technology, enabling a significant improvement in gas-to-liquids commercial competitiveness. Plant start-up is on track for 2002. Liquefied Natural Gas Within BP, the Exploration and Production business is responsible for the supply of Liquefied Natural Gas (LNG) and Gas and Power is responsible for the subsequent marketing and distribution of LNG (see details under Gas and Power -- International Gas and LNG Activities). In Trinidad and Tobago, we have a 34% interest in the first train of the Atlantic LNG plant and are the sole supplier of natural gas to this train, which commenced operations in February 1999. Year 2000 sales to the plant averaged 435 mmcf/d of gas and 1 mb/d of NGL. In the fourth quarter of 2000, government and partner approvals were obtained to expand Atlantic LNG by an additional two trains, through an investment of $900 million gross. BP has a minimum 38.3% interest in the second and third trains and will supply 50% of the gas for the second train and 75% for the third train. In Indonesia, the VICO (100% equally held by BP and LASMO) operations produced in excess of 1.2 bcf/d gas to supply the LNG plant at Bontang. Of this total, approximately 250 mmcf/d is the BP net share. VICO, as well as operating the extensive East Kalimantan pipeline network, is gas co-ordinator for all of the approximate 4 bcf/d gas feedstock to the Bontang facility and is technical advisor to PT Badak, the LNG plant operating company. Bontang, currently the world's largest LNG facility, consists of eight LNG trains with a nominal total capacity of 22.6 million tonnes per annum, with the possibility of expanding to a ninth train being considered. We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction Company (ADGAS), which in 2000 supplied 5.2 million tonnes of LNG. In Australia, our share of LNG produced from the North West Shelf natural gas development (BP 16.7%) remained in line with that of the previous year at 1.3 million tonnes. 33
GAS AND POWER In September 1999, we announced the creation of a new Gas and Power business, which has been reported as a separate segment since January 1, 2000. The Gas and Power business was created to market our substantial natural gas reserves and to develop a leading gas and power marketing and trading business. Since its inception, we have been investing in both organizational capability and capital assets to grow this new business segment. The business is organized into three activities: gas marketing and trading; international gas and liquefied natural gas (LNG); and power activities. On January 1, 2001, the natural gas liquids (NGL) business, located in North America (USA and Canada), was moved to the Gas and Power business from Refining and Marketing. It will be included in the marketing and trading activities. <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ----- ----- ----- ($ million) <S> <C> <C> <C> Turnover ................................................ 16,081 5,323 4,800 Total replacement cost operating profit ................. 186 211 58 Total assets............................................. 4,511 1,682 1,614 Capital expenditure and acquisitions..................... 279 18 95 </TABLE> Marketing and trading activities within the stream are focused on the relatively open and liberalized gas and power markets of North America, the United Kingdom and certain parts of the Rest of Europe, although elements of long-term gas contracting activity are also still included within the Exploration and Production stream. Our business is built on the foundation of our major gas supply reserves being within or in close proximity to these markets. As gas and power markets converge, our recent entry into power marketing and trading is a logical extension of our gas business. We market and trade BP and third party gas and, to a much lesser extent, power and related energy management services. Our NGL business, a part of our North America marketing and trading activities, is engaged in the processing, fractionation and marketing of ethane, propane, butanes and pentanes extracted from natural gas. International gas and LNG activities involve developing opportunities to monetize our upstream gas resources, and as such, are conducted in close collaboration with the Exploration and Production business. Our international gas strategy is to capture a disproportionate share of growth in the international demand for gas and is focused on emerging markets, such as the Asia Pacific region, where substantial demand growth is expected. LNG activities are focused on the marketing and trading of BP and third party LNG. There is close linkage between the LNG supply activities in the upstream business and Gas and Power's LNG marketing and trading activities. In addition to power marketing and trading activities, we are involved in several gas-fired power generation projects. Our power strategy focuses on projects that either monetize our equity gas and/or cogeneration projects on Group sites that contribute additional value from the reduction of Group power costs and/or enable excess power to be sold. Marketing and Trading Activities Our marketing and trading activities are concentrated in the markets of North America and the United Kingdom. Since the creation of Gas and Power, we have realized growth in gas sales volumes from 8.9 bcf/d in 1999 to 14.5 bcf/d in 2000. Much of this growth was realized in North America (76%) and the United Kingdom (15%). <TABLE> <CAPTION> Years ended December 31, ------------------------ Gas sales volumes (a) 2000 1999 1998 ----- ----- ----- (thousand cubic feet per day) <S> <C> <C> <C> UK....................................................... 2,526 1,693 1,910 Rest of Europe........................................... 178 167 72 USA...................................................... 6,524 4,047 3,798 Rest of World............................................ 5,243 3,023 2,739 ----- ----- ----- Total.................................................... 14,471 8,930 8,519 ===== ===== ===== </TABLE> (a) Includes marketing, trading and supply sales. 34
Our policy toward natural gas price risk is described in Item 11 -- Quantitative and Qualitative Disclosures about Market Risk. North America BP is the leading natural gas producer in North America, the world's largest natural gas market. We are building our gas and power marketing and trading business in North America upon this strong foundation. Our 2000 North American total gas sales volumes grew from 5.4 bcf/d in 1999 to 9.7 bcf/d in 2000. Of these volumes, 3.6 bcf/d (1999 3.0 bcf/d) were supplied from BP upstream producing operations. The sales volumes were a mixture of sales to end users, sales to trade counter parties and term sales. Additional volumes associated with `over the counter' transactions (OTC), NYMEX options, and futures (also known as financial trading activity) were a small proportion of total sales. Our North America gas marketing and trading strategy seeks to maximize returns from building a distinctive network of connected assets, customers and activities thereby optimizing our portfolio and supply chain management and adding value through trading. In support of this, during 1999, we announced the acquisition of ProGas, Canada's second largest natural gas aggregator. We have continued to make acquisitions with the September 2000 purchase of IGI Resources, a non-regulated marketer of natural gas to industrial customers in the Pacific Northwest. IGI is well located with respect to our upstream resources and provided access to some 575 customers and gas sales of 0.6 trillion British thermal units per day (Btu/d). We also purchased an 18.5% shareholding in GreenMountain.com, one of the premier green and clean energy consumer marketers in the United States with 135,000 customers in California, Pennsylvania, Connecticut and New Jersey. Marketing and trading of electrical power is a natural extension of our gas business. During 2000, we became a top ten trader of power on the West Coast of the United States. Effective January 1, 2001, the North American natural gas liquids (NGL) business was transferred from Refining and Marketing to Gas and Power. This transfer recognizes that NGL are an integral part of the overall gas value chain and will also take advantage of our gas marketing and trading skill base in North America. The majority of BP's NGL is marketed on a wholesale basis under annual supply contracts that provide for price redetermination based on prevailing market prices. Sales volumes of NGL averaged 324,000 b/d (1999 319,000 b/d). NGL is also supplied to our chemical and refining activities. We operate and/or own natural gas processing facilities across North America with a total capacity of over 12 bcf/d. We own or have an interest in five fractionator plants in Canada and the United States. Two of these are located in Canada in Forst Saskatchewan, Alberta and Sarnia Ontario, and three are located in the United States in Hobbs, New Mexico, Baton Rouge, Louisiana and Mont Belvieu, Texas. During 2000, additional gas processing capacity came on stream in Western Canada to support the growth of our natural gas production in Alberta, as well as BP Chemicals' activities in the province. United Kingdom The gas market in the United Kingdom is significant in size and is one of the most progressive in terms of deregulation when compared with other European markets. BP is the largest producer of natural gas in the UK. Our Gas and Power business is conducted there through BP Gas Marketing Limited, a gas and power marketing and trading company and through BP Energy Limited, a company that provides energy management and combined heat and power (CHP) development services to UK industrial and commercial customers. Total gas sales have grown in the UK from 1.7 bcf/d in 1999 to 2.5 bcf/d in 2000. Of these volumes 1.7 bcf/d (1999 1.3 bcf/d) were supplied from our upstream producing operations. Some of the gas is sold under long term gas supply contracts to customers such as Centrica. However, the majority of gas sales are to commercial and industrial customers, power generation companies and via long-term supply deals with other gas wholesalers. We also trade physical gas on the UK spot market. This year we launched `IdEA', a total energy management service targeted at larger commercial and industrial customers and have had initial success with customers such as GM, Nestle, Ford and others. We also established a contract this year to provide emissions credit management services to IMERYS. We have a 10% interest in the Interconnector, a 1.9 bcf/d, 240-kilometre, 40-inch sub-sea natural gas pipeline between Bacton in the UK and Zeebrugge in Belgium, which effectively links the gas markets of the UK and Continental Europe. Rest of Europe We are beginning to build a gas and power marketing and trading business in Northern and Southern Europe. Our interest in the European market is driven by the size and growth potential of the market, deregulation and the proximity of BP gas supplies. 35
In Northern Europe, we have a 25.5% interest in Ruhrgas, Germany's largest gas transmission and distribution company. In October 1999, we commenced a 15-year contract to supply 15 billion cubic metres of natural gas to Ruhrgas. This gas is supplied to Ruhrgas from the UK via the Interconnector. In addition, during 2000 we established a marketing office in Rotterdam and commenced marketing activities in the Netherlands and Belgium. BP's sales volumes in Northern Europe were not significant by the end of 2000. In Southern Europe, our activities in 2000 were largely focused in Spain, a gas market that has been projected to double in size from 1999 to 2006 and which has generally been liberalized more quickly than many other EU countries. We were the first foreign company to secure a licence permitting us to market natural gas to industrial consumers outside the former monopoly, and by the fourth quarter of 2000 had secured some 7% of the eligible industrial market. In December 2000, we applied for and were awarded a further licence to market power. In the summer of 2000, with BP's oil marketing business, we launched BP Energia, an on-line integrated offer of energy products and services to customers. International Gas and LNG Our international gas and LNG activities are focused on developing worldwide opportunities to capture international gas growth and to monetize our upstream gas resources. Construction is underway on the Bahia de Bizkaia project in Bilbao, Spain, an integrated 2.75 billion cubic metres per annum (bcma) LNG import/regasification and 800 megawatt combined cycle, gas-fired power generation facility. BP has a 25% equity share in the facility and BP equity gas from Trinidad and Tobago will supply the facility. After regasification of the LNG, approximately 40% of the gas will feed the power plant, while the remaining gas will be fed into the local natural gas distribution system. China is another area of activity. Currently, gas meets only two percent of China's energy needs, but this is expected to increase to between seven and eight percent by 2010. BP announced in March 2000 that it had plans to form a natural gas marketing joint venture with PetroChina aimed at supplying the rapidly growing energy markets of eastern China. The two companies intend to co-operate in building infrastructure, potentially including an LNG terminal and to supply imported and domestic gas to the regions around Shanghai and the Yangtze River Delta. The alliance additionally allows BP involvement in the West-East China gas pipeline and, longer term, the potential to market gas from East Siberia where BP has an interest in the substantial Kovyktinskoye field. Both these options are subject to feasibility studies and appropriate approvals. In August 2000, we signed a joint venture framework agreement with PetroChina for gas marketing in the East China provinces of Anhui, Jiangsu, Zheijiang and the Shanghai municipality. We are one of the four bidders for China's Guangdong LNG regasification terminal. In March 2001, BP was selected to enter into exclusive negotiations to secure the position as the foreign partner in the joint venture tasked to develop China's first LNG import terminal. We recently entered into a long term gas sales agreement to supply and deliver 33.6 trillion Btu per year of gas for 20 years in the form of LNG to AES for their power projects in the Dominican Republic in the Caribbean, beginning mid 2002. This is the first BP branded LNG sale with no assigned reserves. We were one of three successful bidders for LNG tanker offloading capacity at the Cove Point import facility in Maryland on the Eastern seaboard of the USA. We obtained access to 250 mmcf/d of Cove Point's capacity. The terminal is expected to be in operation in 2002. Cove Point will provide an important access point for bringing our LNG supplies into the US market. In July 2000, we ordered two LNG tankers from Samsung Heavy Industries in Koje, South Korea. The order, worth in excess of $300 million, includes an option to purchase three additional ships. Delivery on the first is expected in 2002 and on the second in 2003. These LNG ships will be owned and operated by BP Shipping and will provide valuable LNG transportation capacity. Capital expenditure on the LNG tankers in 2000 was $130 million. As described under the heading `Exploration and Production, Midstream activities -- liquefied natural gas', our major LNG supplies are from Trinidad and Tobago, VICO in Indonesia, ADGAS in Abu Dhabi and the Northwest Shelf in Australia. Power Activities In addition to power marketing and trading, we are currently involved in four power generation construction projects. We primarily participate in power projects that support monetization of our equity gas and cogeneration projects on BP sites that are advantaged by the existence of gas-to-power capabilities, for example in connection with chemical manufacturing. Three of the projects are described below, while the fourth project, the Bahia de Bizkaia project in Bilbao, Spain, is covered under the description of International Gas and LNG, as it is primarily a gas monetization project. 36
Capital expenditure in connection with our power generation projects totaled $77 million in 2000, and is expected to increase to $196 million in 2001 as we work to bring each plant on line. We have announced plans at BP's largest refining and petrochemical complex, located in Texas City, Texas, for the South Houston Integrated Site Cogeneration project. BP will have 90% ownership of this 820 MW cogeneration plant, which will provide low cost steam, power and process heat to our refining and chemicals businesses. The project will provide improved generation efficiency, reduced power costs and reduced nitrogen oxide emissions at the site. BP will supply gas to the plant and its excess generation capacity will be used to support power marketing and trading activities. At the BP Chemicals' site in Baglan, south Wales, General Electric is testing and commercializing the world's largest single gas turbine in a 500 MW combined cycle cogeneration project. The plant will provide both steam and electricity to BP Chemicals, reducing site energy costs. BP will provide gas to the power plant under a 15-year contract and will market the surplus power from the plant to local industrial users. In December, our power plant project at Great Yarmouth in the UK entered its commissioning phase. This project is a 400 MW gas-fired plant, which will be operated as a merchant plant, i.e. that it sells to `spot' customers without any long-term contracts, and BP is expected to provide gas to the plant. While initially BP owned 60% of this project, BP is now the sole owner as a result of the ARCO acquisition. Capital expenditure at Great Yarmouth in 2000 was $60 million (1999 $20 million and 1998 $20 million). 37
REFINING AND MARKETING Our Refining and Marketing business is responsible for the supply and trading, refining, marketing and transportation of crude oil and petroleum products to wholesale and retail customers. Until December 31, 2000, it was also responsible for the wholesale marketing of natural gas liquids (NGL) in the USA and Canada, which was transfered to the Gas and Power stream on January 1,2001. BP markets its products in over 100 countries. It operates primarily in Europe and North America, but also markets its products across South America, Australasia and in parts of South East Asia and Africa. <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ----- ----- ----- ($ million) <S> <C> <C> <C> Turnover (a)............................................. 112,815 62,893 48,437 Total replacement cost operating profit.................. 3,908 1,840 2,564 Total assets............................................. 47,879 27,248 21,029 Capital expenditure and acquisitions..................... 8,750 1,634 1,937 ($ per barrel) Global Indicator Refining Margin (b)..................... 4.22 1.24 2.10 - ---------- </TABLE> (a) Excludes BP's share of joint venture turnover of $13,112 million in 2000, $17,117 million in 1999, and $15,080 million in 1998. (b) The Global Indicator Refining Margin (GIM) is the average of seven regional indicator margins weighted for BP's crude refining capacity in each region. Each regional indicator margin is based on a single representative crude with product yields characteristic of the typical level of upgrading complexity. There are four key components of the Refining and Marketing stream each with its own focus and strengths. In refining, the focus is on top-quartile performance and integration across the Group; to measure this we primarily use the regional refining surveys by Solomon Associates to assess our competitive position against benchmarked industry measures such as costs per barrel. In retail, the focus is on high-growth geographical areas and customer segments through the convenience-store market. In lubricants, Castrol and BP are leading brands, giving increased access to growth in both margin and volume. Finally, the stream's commercial and industrial activities, such as aviation, are being refocused into customer-focused business segments to capture margin and growth. Refining and Marketing manages a portfolio of assets which we believe are competitively advantaged across the chain of downstream activities. Such advantage may derive from several factors, including location, operating cost and physical asset quality. The merger of BP and Amoco on December 31, 1998 and the acquisitions of ARCO, Burmah Castrol and the ExxonMobil interest in the fuels business of the BP/Mobil European joint venture in 2000 substantially strengthened our position in refining and marketing. We are one of the leading refiners and marketers of gasoline and hydrocarbon products in the USA. We have extensive retail and commercial businesses in the UK, the Rest of Europe, Australasia, Africa and South East Asia. Worldwide, BP continues to be a leading marketer of fuels, served by a refining network with key refineries among the top performers in their regions. During 2000, the acquisitions of ARCO and Burmah Castrol added approximately 26,000 employees to the refining and marketing business. This increase was partly offset by the integration and rationalization of business activities during the year which resulted in some 3,600 employees leaving. The overall effect of the activity in 2000 was to increase employee numbers from 45,250 at the start of the year to 67,700 at the year end. 38
In December 1999, we agreed with ExxonMobil the principles under which the BP/Mobil European joint venture would be dissolved in response to the European Commission's authorization of the Exxon and Mobil merger. Within the joint venture BP operated and had a 70% interest in the fuels refining and marketing operation, and ExxonMobil operated and had a 51% interest in the lubricants business. Under the agreement BP purchased ExxonMobil's 30% interest in the fuels business for $1.5 billion with effect from August 1, 2000. In addition, the two companies divided the assets of the lubricants business broadly in line with their equity stakes (Mobil 51%, BP 49%). This dissolution was substantially completed in 2000, thus increasing BP's share of all European markets where the fuels joint venture was active. ExxonMobil retained ownership of their Gravenchon (France) lubricants refinery, and acquired BP's share in the Dunkerque (France) base oil refinery. BP retained ownership of the Neuhof (Germany) lubricants refinery. Refining Our key objective is to operate a refining system more profitably than those of our competitors. We constantly review our refineries in terms of advantaged characteristics and dispose of those which do not meet the criteria. Advantaged characteristics relate to supply -- the refinery's geographic position in relation to the market; clean fuels -- how the refinery supports our clean fuels strategy; and integration value -- how the refinery adds value by virtue of integration with other parts of the Group's business. We believe that one result of pursuing this objective will be the reduction in the ratio between our own refining supply and the volumes we market to roughly 60-70%, from the level of around 90% existing in 1999. In addition to applying the criteria relating to advantaged characteristics, BP's strong focus on reducing operating costs and optimizing yields will continue. Our refineries are integrated with our global supply and trading activities. An internal measure which we use to target and monitor performance in this area is commercial performance, measured in cents per barrel. This is the aggregate incremental income resulting from optimization of refining's crude and product slates under prevailing oil market price structures and taking into account sustainable operational improvements. Commercial performance has provided over $0.23 per barrel of new value each year since 1998. This is incremental commercial performance over and above the previous year. Applying a simple rule of thumb, a $0.01 per barrel commercial performance improvement equates to about $8 million of costs. We believe that the tight integration of our trading and supply activities is the main reason we can realize this premium. Consistent with our assessment of advantaged characteristics, we sold the Alliance refinery in Louisiana, USA, in September 2000. In addition, BP's 30% ownership in its Singapore refinery, along with three wholly-owned US refineries, Salt Lake City (Utah), Mandan (North Dakota), and Yorktown (Virginia), and their associated facilities, have been offered for sale. We are targeting to complete the sales process in 2001. This will reduce our gross crude distillation capacity to 2,913 mb/d. Through the combination with ARCO, BP acquired full ownership of ARCO's Carson (California) and Cherry Point (Washington) fuels refineries. In addition, BP owns and operates three further US fuels refineries at Texas City (Texas), Whiting (Indiana), and Toledo (Ohio). BP operates seven European fuels refineries. These are Bayernoil (Germany), Castellon (Spain), Coryton (UK), Grangemouth (UK), Lavera (France), Mersin (Turkey) and Nerefco (the Netherlands). All the refineries are wholly owned by BP, except for Bayernoil, Mersin, and Nerefco where BP's interest is 55%, 68%, and 69%, respectively. Additionally, BP has a 17% interest in the Reichstett refinery in France, with the other shareholders being Total 18%, and Shell, its operator, 65%. In the rest of the world BP operates three principal refineries: at Brisbane and Kwinana in Australia, and Singapore. BP has a 50% interest in the Durban refinery in South Africa, which is operated by our partner Shell, and a 24% shareholding in the New Zealand Refining Company which is publicly listed on the New Zealand stock exchange. 39
The following tables set out by area the crude oil and other feedstocks processed in the years 1998 through 2000 by the BP Group for its own account and for third parties, and for the Group by other refiners under processing agreements, and the Group's refinery capacity utilization. <TABLE> <CAPTION> Years ended December 31, ------------------------ Refinery throughputs 2000 1999 1998 ----- ----- ----- (thousand barrels per day) <S> <C> <C> <C> United Kingdom (a)....................................... 324 271 296 Rest of Europe (a)....................................... 602 540 551 United States............................................ 1,625 1,340 1,489 Rest of World............................................ 365 371 362 ----- ----- ----- 2,916 2,522 2,698 For BP by others......................................... 12 19 13 ----- ----- ----- Total.................................................... 2,928 2,541 2,711 ===== ===== ===== Refinery capacity utilization Crude distillation capacity at December 31, (a) (b)...... 3,203 2,801 2,815 Crude distillation capacity utilization (c).............. 95% 95% 94% </TABLE> - ---------- (a) Includes the BP share of the BP/Mobil European joint venture until August 1, 2000. (b) The crude distillation capacity figures are based on gross rated capacity which assumes no loss of capacity due to shutdowns. The figures for 2000 reflect the unwinding of the BP/Mobil European joint venture, Alliance refinery sale, and acquisition of ARCO refineries. The figures for 1998 reflect the disposal of the Lima refinery in mid-1998. (c) Crude distillation capacity utilization is defined as the percentage utilization of capacity per calendar day over the year after making allowances for average annual shutdowns at BP refineries (net rated capacity). In 2000, we operated our refineries in the USA at an average of 97% of net rated capacity (1999, 95% and 1998, 95%), our European refineries at 96% (1999, 94% and 1998, 95%) and our refineries in the rest of the world at 87% (1999, 96% and 1998, 89%). Deeper integration between Refining and Marketing and Chemicals is key to increasing profitability and strengthening our relative competitive position. In November we announced the formation of the South Houston Integrated Site, an organizational structure which encompasses our operations at the Chocolate Bayou chemical plant, the Texas City chemical plant, the Texas City refinery, chemical operations at Cedar Bayou and Stratton Ridge, and BP's assets at the Sterling Chemicals' site in Texas City. The South Houston Integrated Site organization will enable BP to capture the efficiencies and synergies from operating these manufacturing facilities as one integrated site in a similar way to that at Grangemouth. In 2000 we completed construction of a project at the Brisbane refinery, Australia enabling the production of low sulphur fuels, starting October 2000. Capital expenditure at the refinery in 2000 was $110 million (1999 $50 million and 1998 $20 million). The Toledo refining repositioning project was completed in 1999. Capital expenditure on this project was $50 million in 1999 (1998 $130 million). Planned investment on clean fuels in European refineries is expected to be approximately $0.3 billion in the next four years, with a similar total in the US. In 2000, emissions of greenhouse gases (primarily carbon dioxide) were reduced by more than 5% compared with 1998, primarily through operational actions, including approximately 2% since 1999. Additional reductions are planned through continued energy efficiency improvements and participation in the internal BP trading programme. 40
Marketing Marketing comprises three business areas: Retail, Commercial and Industrial, and Lubricants. We market a comprehensive range of refined oil products worldwide. These products include gasoline, gasoil, marine and aviation fuels, heating fuels, LPG, lubricants and bitumen. The following table sets out refined product sales by area. A significant increase in sales was achieved in 2000 as a result of the acquisition of ARCO and ExxonMobil's interests in the BP/Mobil European fuels business during the year. <TABLE> <CAPTION> Years ended December 31, ------------------------ Sales of refined products (a) 2000 1999 1998 ----- ----- ----- (thousand barrels per day) Marketing sales: <S> <C> <C> <C> United Kingdom (b)(c).................................. 256 235 261 Rest of Europe (b)..................................... 901 794 769 United States.......................................... 1,937 1,542 1,504 Rest of World.......................................... 662 615 603 ----- ----- ----- Total marketing sales (d)................................ 3,756 3,186 3,137 Trading/supply sales (d)................................. 2,103 1,816 1,665 ----- ----- ----- Total refined products................................... 5,859 5,002 4,802 ===== ===== ===== ($ million) Proceeds from sale of refined products (b)............... 79,171 44,248 44,446 </TABLE> - ---------- (a) Excludes sales to other BP businesses. (b) Includes the BP share of the BP/Mobil European joint venture until August 1, 2000. (c) UK area includes the UK-based international activities of Refining and Marketing. (d) Marketing sales are sales to service stations, end-consumers, bulk buyers, jobbers and small resellers. Trading/supply sales are to large unbranded resellers and other oil companies. The following table sets out marketing sales by major product group: <TABLE> <CAPTION> Years ended December 31, ------------------------ Marketing sales by product 2000 1999 1998 ----- ----- ----- (thousand barrels per day) <S> <C> <C> <C> Aviation fuel............................................ 474 366 292 Gasolines................................................ 1,505 1,298 1,256 Middle distillates....................................... 939 765 796 Fuel oil................................................. 338 319 322 Other products........................................... 500 438 471 ----- ----- ----- Total marketing sales ................................... 3,756 3,186 3,137 ===== ===== ===== </TABLE> In marketing our aim is to grow our customer base, both in existing and new markets -- in terms of attracting new customers and by covering a wider geographic area. We are aiming at increasing our per-customer revenue by attracting retail customers to spend more in convenience stores and business customers to spend more on value-added services and solutions. Our objective is to create a more capital-efficient, higher-return business by differentiating where we choose to invest directly from where we seek to invest through partners. In addition we recognize that our customers are demanding a wider choice of fuels, particularly fuels that are cleaner and more efficient. 41
Retail In retail, we differentiate between two distinct segments: a fuels segment in which we distribute fuel to retail customers through dealers and jobbers, and a convenience segment, incorporating an integrated fuel and convenience store offering, the operation of which will either be directly managed or franchised. We plan to concentrate investment primarily in developing additional store space on existing real estate in our core metropolitan markets. <TABLE> <CAPTION> Years ended December 31, ------------------------ Shop sales (a) 2000 1999 1998 ----- ----- ----- ($million) <S> <C> <C> <C> UK....................................................... 357 265 231 Rest of Europe........................................... 663 569 513 USA...................................................... 1,251 542 543 Rest of world............................................ 353 365 356 ----- ----- ----- Total.................................................... 2,624 1,741 1,643 ===== ===== ===== Direct -- managed........................................ 1,397 994 991 Franchise................................................ 1,154 707 626 Shop alliances........................................... 73 40 26 ----- ----- ----- Total.................................................... 2,624 1,741 1,643 ===== ===== ===== </TABLE> (a) Shop sales reported are sales through direct managed stations, franchisees and the BP share of shop alliances and joint ventures. Sales figures exclude sales taxes and lottery sales but include quick service restaurant sales. The sales include the BP share of the relevant sales within the BP/Mobil European joint venture, until August 1, 2000. Our retail network is concentrated in Europe and the USA, with established operations in Australasia and Southern Africa. We are developing networks in China, Poland, Russia and Venezuela. During 2000 we launched a retail strategy that builds on our advantaged locations, strong market positions and brand that will offer our customers cleaner fuels, a wider range of services and a distinctive food offer. The opening of the first 'BP Connect' site reflecting the new brand image, site design and offer took place in London during December, 2000, and by the end of the year four 'BP Connect' sites were in operation. During 2001, the business focus will be on rolling out the new brand image, site design and offer principally in designated metropolitan markets in the USA and the UK. We expect to open around 320 new 'BP Connect' sites in 2001. At the same time as we are rolling out the new convenience offer, we continue to improve the efficiency of our retail network by reducing operating costs through a process of regularly reviewing the network. Actions taken during 2000 have included divesting sites and networks, principally in those markets where our growth will be focused on a fuels only offer delivered through dealers and jobbers. Alongside this activity, we have continued to upgrade existing sites and invest in new sites, principally in markets where we believe there is growing demand for our full convenience offer. This strategy is applied to all our retail networks, including those that were operated for part of the year within the BP/Mobil European joint venture. At December 31, 2000, there were approximately 29,000 BP, Amoco and ARCO branded service stations worldwide. This number is expected to decline over the next few years. During 2000 we continued implementation of two major environmental initiatives. In 1999 we announced our 'Clean Cities' initiative to market cleaner fuels in some of the world's most polluted cities by the end of 2000. During 2000 we launched this initiative in 41 major cities around the globe to bring the total number of cities covered by the year end to 56. We also announced in 1999 a programme to incorporate solar power into our service stations. By the end of 2000 over 200 service stations had been fitted with solar panels having a total power capacity greater than 3.5 MW. At December 31, 2000, BP's retail network in the USA comprised about 17,300 service stations of which approximately 11,900 were jobber owned. Acquisition of ARCO during the year has added about 1,800 service stations and convenience locations on the West Coast to the existing networks, which are concentrated mainly in the Midwest, East and Southeast. Developments in the USA during 2000 included the divestment of about 360 service stations in line with the strategy to concentrate ownership of real estate in markets designated for development of the convenience offer. 42
In the UK and the Rest of Europe, BP's network comprised about 7,900 service stations at December 31, 2000. We continued to expand our joint venture agreement with Safeway p.l.c. in the UK and have now redeveloped 51 sites incorporating a Safeway convenience store. In France, we continued to implement co-operative retailing arrangements with our partner Huit a Huit, and opened a further 17 stores in this format during 2000 bringing the total to 50. In Poland and Russia, we continued to expand our retail network, with the addition of a further 26 retail sites during 2000 giving a total of 161 in these countries. At December 31, 2000 BP's retail network in the rest of the world comprised some 3,800 service stations. Our established networks are primarily in Australia, New Zealand, Southern Africa and South East Asia. In addition BP now has some 146 branded sites in Poland, Venezuela, China and Japan where we are expanding networks. During 2000 as part of our strategic alliances in China BP has agreed with Sinopec in principle to form a joint venture to acquire, revamp or build 500 fuels service stations in the Zhejang Province, East China. The dual-branded service stations will sell gasoline produced by Sinopec and sell other petroleum products supplied by each partner. In addition BP has agreed with PetroChina in principle to build a fuels marketing business in China's coastal provinces with the prospect of further expansion into other regions. Including some existing sites, the companies aim to build or acquire 150 service stations in the first year of operation, and to maintain that momentum towards building a significant retail presence within five to seven years. Commercial and Industrial In our Commercial and Industrial business we aim to attract more customers through innovation in multi-product offers and cleaner fuels, packaged with a range of value-added services and solutions, thus aiming to increase customer spend and growth in volumes at above the rate of market growth. For example, our offer to Commercial and Industrial customers has expanded to include BP's leading edge risk management services with a complete line of clean fuels and energy saving lubricants. Our Commercial and Industrial business operates in Australasia, Europe, Southern Africa and the USA. This business includes the supply of fuel, LPG, and bitumen to industrial and domestic users. In 2000, our business grew through the acquisition of ARCO, the ExxonMobil share of the BP/Mobil European fuels business and the creation of bpdirect.com, an e-commerce web site for US customers coast to coast. Our aviation business sells jet and other aviation fuels to airlines and general aviation customers as well as providing technical services to airlines and airports. In 2000, BP's aviation business purchased a turbine lubricants business to further expand our customer offer. During the last few years, the aviation business has strengthened its position in established markets and pursued opportunities in new or emerging markets. The business now markets in approximately 95 countries and is the third largest jet fuel supplier globally. Lubricants We manufacture and market lubricant products and also supply related products and services to business customers and end-consumers in over 60 countries directly, and to the rest of the world through local distributors. Our business is concentrated on the higher value sectors of automotive lubricants, especially in the consumer sector, but also has a strong presence in commercial sectors such as marine and specialized industrial segments. Our Lubricants business was transformed during 2000 by the acquisition in July of Burmah Castrol, which has operations in over 50 countries and has the world's leading automotive lubricants brand. During the year, the BP/Mobil European joint venture was dissolved with BP resuming operation of business in line with our 49% share of the lubricants business. We have four major brands under our control (BP, Castrol, Duckhams and Veedol). Our lubricants business is organized by market segment. The main characteristics of each part of the business are as follows: Consumer markets: We supply lubricants, other products and related business services to intermediate customers (e.g. retailers, workshops) who in turn serve end-consumers (car, motorcycle, leisure craft owners) in the mature markets of Europe and North America and also in the fast growing markets of the developing world (Asia, India, Middle East, South America and Africa). The Castrol brand is recognized worldwide and we believe it provides us with a significant competitive advantage. Commercial vehicle and general industrial markets: We supply lubricants and lubricant related services to automotive manufacturers and other industrial customers. 43
Marine market: We supply lubricants and fuels, on a global basis, to major shipping companies as well as to small fishing vessel operators. We are the leading global participant in the marine lubricants market and operate a network of offices and supply points in more than 900 ports across 90 countries. During 2000, we formed an innovative global strategic partnership `Marine Alliance' with Unitor, a major supplier of marine consumables, to supply a full range of products and services to marine customers. This partnership is targeting market growth while enabling costs to be eliminated. Specialist industrial market: We supply metalworking fluids and lubricants alongside a range of business services, such as fluid management, to the metal component manufacturing sector. We also have a significant high performance industrial lubricants business in some key markets. Supply and Marketing of NGL As of January 1, 2001, our NGL business was transferred to the Gas and Power stream and the activities are described in the Gas and Power section under the heading 'Marketing and Trading Activities -- North America'. Supply and Trading We are one of the world's major traders of crude oil and refined products, dealing extensively in physical and futures markets. Our portfolio of purchases and sales is spread among spot, term, exchange and other arrangements, and covers a range of sources and customers to match the location and quality requirements of the Group's refineries and the various markets, while seeking to ensure flexibility and cost-competitiveness. In addition, the Group's oil-trading division undertakes trading in physical and paper markets in order to contribute to the Group's income. Transportation Our Refining and Marketing business owns, operates or has an interest in extensive transportation facilities for crude oil, refined products and petrochemical feedstocks in the US. It also has interests in a number of crude oil and product pipelines in the UK and the Rest of Europe. We transport crude oil to our refineries principally by ship and through pipelines linking our refineries with import terminals. We have interests in seven major crude oil pipelines in the UK and the Rest of Europe and thirteen in the USA. Bulk products are transported between refineries and storage terminals by pipeline, ship, barge, and rail. Onward delivery to customers is primarily by road. We have interests in nine major product pipelines in the UK and the Rest of Europe and six in the USA. We also have interests in a major natural gas pipeline, four NGL pipelines, and many smaller pipelines. In total, we have interests in some 36,000 kilometres of pipeline, of which about three-quarters are located in North America. In March 2000, BP acquired an additional one-third interest in Destin Pipeline LLC in the Gulf of Mexico increasing our ownership to two-thirds. We assumed operatorship in July, and will assume control over commercial activities in January, 2002. In May 2000, BP acquired several transportation assets of ARCO Pipeline Company (as part of the ARCO acquisition) including refined products, chemicals, NGL and selected crude oil pipelines. In 2000, BP acquired ownership interests in Olympic Pipeline LLC, a former ARCO refined products joint venture pipeline serving Seattle, Washington and Portland, Oregon. We purchased a further 25% in July giving us 62.5% ownership of Olympic and assumed operatorship. In November 2000, BP sold its carbon dioxide transportation assets in West Texas to Occidental Petroleum. Shipping BP Shipping owns or operates an international fleet of crude and product tankers and LNG carriers carrying cargoes for the Group and for third parties. It also offers a wide range of services to Group and third party marine customers. At December 31, 2000 the Group owned an international fleet of four Product Carriers, totalling approximately 0.15 million deadweight tons (dwt). It also had an interest in six LNG carriers which are dedicated to transportation of Australian North West Shelf LNG. 44
Excluding BP companies in the USA, the Group had eighteen tankers (eight Very Large Crude Carriers (VLCCs), eight Medium Crude Carriers and two Product Carriers) totalling approximately 3.57 million dwt, on long-term charter at December 31, 2000. BP companies in the USA had 26 tankers (two VLCCs and 17 Medium Crude Carriers and seven Product Carriers), totalling approximately 2.72 million dwt on long-term charter along with five barges, and five other barges on short-term charter. Four of the Medium Crude Carriers, totalling 0.65 million dwt, were in temporary lay-up at the end of 2000. In addition, a large number of small vessels are used by Group companies around the world. BP has contracted to bareboat charter two more Product Carriers for delivery in 2001 and to build three Medium Crude Carriers for delivery between 2003 and 2005. 45
CHEMICALS Our Chemicals business is a major producer of petrochemicals through subsidiaries and associated undertakings. BP has operations principally in the USA and Europe, and increasingly in the Asia-Pacific region. Chemicals is also responsible for the supply, marketing and distribution of chemical products to bulk, wholesale and retail customers. <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ----- ----- ----- ($ million) <S> <C> <C> <C> Turnover (a)............................................. 11,247 9,392 9,691 Total replacement cost operating profit ................. 760 686 1,100 Total assets............................................. 13,674 13,021 12,562 Capital expenditure and acquisitions..................... 1,585 1,215 1,606 ($/tonne) Chemicals Indicator Margin (b)........................... 121(c) 114 139 </TABLE> (a) Excludes BP's share of joint venture turnover of $67 million in 2000, nil in 1999 and 1998. (b) The Chemicals Indicator Margin (CIM) is a weighted average of externally-based product margins. It is based on a market data collected by Chem Systems in their quarterly market analyses, then weighted based on BP's product portfolio. While it does not cover our entire portfolio, it includes a broader range of products than our previous indicator. Among the products and businesses covered in the CIM are the olefins and derivatives, the aromatics and derivatives, linear alpha olefins, acetic acid, vinyl acetate monomer and nitriles. Not included are fabrics and fibres, plastic fabrications, poly alpha olefins, anhydrides, engineering polymers and carbon fibres, speciality intermediates, and the remaining parts of the solvents and acetyls businesses. (c) Provisional. The data for the current year is based on eleven months of actual data and one month of provisional data. Chemicals margins are largely cyclical in nature and in 2001, the chemical industry's external environment is expected to continue to be under pressure. The external drivers of our results in 2001 are expected to be market demand levels, new industry supply starting up and pressures on feedstock prices. Our strategy is to create competitive advantage in petrochemicals through adding value to Group hydrocarbons, industry cost leadership, world-leading technology, strong market positions, and a bias to high growth products. The Chemicals portfolio comprises three main sectors: Aromatics and Derivatives. In this sector our strategy is focused on extending current leading global positions, with new capacity and increased leadership in technology. Olefins and Polymers. This sector will be repositioned during 2001 with the proposed deals with Solvay and an increased share of Erdolchemie. Combined with the Appryl transaction in 2000; we expect these steps will take us into a position among the global market leaders. For management purposes the Olefins and Polymers sector is split into two geographic regions; Europe, Africa and the Middle East and the Americas and Asia. Intermediates. In this sector we offer a distinctive portfolio with leading technologies. Our investment will be in growth markets and will be supported by active portfolio management beginning with the divestment of the Fabrics and Fibres and the Plastic Fabrication Group (the Fabrications busineses). The portfolio is underpinned by five strategic tenets: Adding value to BP Group hydrocarbons. As the petrochemicals arm of an 'oil major', this is a key element of our competitive advantage, notably by combining feedstock, refining and chemical processing across large integrated sites/sytems. An example of this is in the Houston area where pipelines and a single management structure allow us to operate four, previously separate, sites as a single-system, the South Houston Integrated site. 46
Industry cost leadership. Increasing competitive pressures in the chemicals industry require an enduring focus on cost reduction and we have made cost management an ongoing part of our business. We plan to aggressively reduce underlying costs in 2001 through a number of targeted actions e.g. lower costs from more efficient procurement, reduced waste in our conversion processes and the application of new technology. We also intend to manage costs structurally, by focusing our investment on a limited number of world-class manufacturing sites. By limiting the number of sites, we benefit from increased economies of scale and integration of chemical operations along the various value chains associated with our portfolio. World leading technology. We believe technology will continue to distinguish the most successful companies from their competitors. Leading technology makes us a preferred supplier and a preferred joint venture partner, and this in turn should bring us increased market share and access to new markets. We intend to maintain and extend our leadership in the fundamental technologies that underpin our core businesses. By way of example, our strengths in catalysis, oxidation and fluid bed technology continue to enhance our leadership positions across the portfolio from polymers to basic petrochemicals. BP already has a number of leading technologies in operation and is currently investing in production capacity, utilizing recent breakthroughs in butanediol, vinyl acetate monomer and ethyl acetate manufacture. Strong market positions. This can be measured in a number of ways, such as market share, growth potential or performance in terms of returns. We have global leadership in paraxylene, purified teraphthalic acid (PTA), acetic acid, acrylonitrile, trimellitic anhydride (TMA) and a number of other products. We have also instituted a programme of marketing initiatives to improve our commercial capability. The programme includes developments in e-commerce, including the introduction of web-based marketing channels. Bias to higher growth products. The majority of the BP portfolio is in market sectors which have historically grown faster than the industry average. We will therefore continue to focus our portfolio, by investing in areas offering a good fit and divesting where there is insufficient alignment, with the strategic tenets described above. During 2000, we reviewed our strategic direction as the petrochemicals arm of an integrated energy company and announced structural changes that will change the portfolio of businesses within Chemicals and reorganized our internal management structure into four business areas. The most significant structural changes were as follows: - -- We announced our intention to acquire from Bayer the 50% of Erdoelchemie we do not already own; we expect the transaction to complete in the second quarter of 2001. - -- We and Solvay announced in December 2000 that we had signed a memorandum of understanding aimed at strengthening our polymers businesses in both Europe and the United States. Solvay will transfer its US and European polypropylene businesses to BP. The two companies will combine our European high-density polyethylene businesses into a 50-50 joint venture. In the US, the agreement will lead to a 49%/51% joint venture for Solvay's current high density polyethylene business. In addition, BP will transfer its engineering polymers business to Solvay. The proposed transaction will be subject to the final agreement of both parties and to regulatory approval by the relevant authorities, as well as consultation with workers' representatives. Completion is anticipated in mid-2001. Appryl, the French polypropylene joint venture formed by BP and Elf Atochem in 1986, was dissolved with effect from December 29, 2000. BP took over the 280 thousand tonnes per annum (ktepa) polypropylene plant at Grangemouth, UK, which started production in September 2000. BP and ATOFINA have set up a 50-50 manufacturing joint venture in Lavera, France, operated by ATOFINA. Production from the plant will be split equally between the two partners. ATOFINA will take over the site at Gonfreville, France, and the automotive compounds business. In January 2001, we announced our intention to divest the Fabrications businesses. This will allow us to focus on a narrower set of leading global positions, linked more closely to BP's hydrocarbon streams. 47
Manufacturing Facilities BP has large-scale manufacturing facilities in Europe and the USA. The Group's major sites, with our share of their capacities are: Grangemouth (2,184 ktepa) and Hull (1,453 ktepa) in the UK; Lavera (1,836 ktepa) in France; Marl (636 ktepa) and Dormagen (2,325 ktepa) in Germany; Geel (1,772 ktepa) in Belgium; and Texas City, Texas (2,913 ktepa), Chocolate Bayou, Texas (3,248 ktepa), Decatur, Alabama (2,237 ktepa), and Cooper River, South Carolina (1,328 ktepa) in the USA. We also aim to grow in the Asia-Pacific region, which offers prospects for demand growth. The intention is to build further on the positions that the Group now holds in Taiwan, China, Malaysia and Korea through deeper investment and commercial relationships. Our share of capacity in Asia (largely through joint ventures) amounts to about 2,800 ktepa as follows: Indonesia (470 ktepa), Korea (661 ktepa), Malaysia (848 ktepa), Taiwan (693 ktepa) and China (100 ktepa). <TABLE> <CAPTION> Years ended December 31, -------------------------- Production by region 2000 1999 1998 ----- ----- ----- (thousand tonnes) <S> <C> <C> <C> UK....................................................... 3,137 3,737 3,734 Rest of Europe........................................... 6,713 5,993 5,648 USA...................................................... 9,874 9,917 9,148 Rest of World............................................ 2,341 2,206 2,040 ----- ----- ----- Total Production (a)..................................... 22,065 21,853 20,570 ===== ===== ===== </TABLE> (a) Includes BP share of associated undertakings and other interests in production. The following table shows BP production capacity by major products and by product group at December 31,2000. <TABLE> <CAPTION> Olefins Olefins Aromatics and Polymers and Polymers and Derivatives Europe America/Asia Intermediates Total --------------- ------------ ------------ ------------- ----- (thousand tonnes per annum) <S> <C> <C> <C> <C> <C> Purified teraphthalic acid...... 5,408 -- -- -- 5,408 Ethylene........................ -- 1,172 1,587 -- 2,759 Paraxylene...................... 2,558 -- -- -- 2,558 Polypropylene................... -- 746 1,319 -- 2,065 Styrenics....................... -- 1,477 -- -- 1,477 Polyethylene.................... -- 813 420 -- 1,233 Acetic acid/anhydride........... -- -- -- 1,821 1,821 Linear/poly alpha olefins....... -- -- -- 987 987 Acrylonitrile................... -- -- -- 880 880 Other (a)....................... 424 3,506 826 2,932 7,688 ------ ------ ------ ------ ------ Total 8,390 7,714 4,152 6,620 26,876 ====== ====== ====== ====== ====== </TABLE> - ------------ (a) Includes BP 50% share of Erdolchemie. BP's petrochemical products are sold to companies in a number of industries that manufacture components used in a wide range of applications. These include the agriculture, automotive, construction, furniture, household products, insulation, packaging, paint, pharmaceuticals and textile industries. Our products are marketed through a network of sales personnel and agents who also provide technical services. 48
Aromatics and Derivatives The leading market positions of our key products give us access to a wide range of high-quality options, both in terms of investments and growth options. We strive to be number one or two in terms of market share in the markets in which we compete, and we are currently a global leader in PTA and paraxylene. We aim to bias our portfolio towards products which have been growing about 8-10% a year overall. This is about three times the rate of global economic growth and compares with an estimated average of 4% for the petrochemicals industry as a whole. We plan to continue to focus our portfolio in areas where we have clear competitive advantage driven by the strategy described earlier. We withdrew from our joint-venture Singapore aromatics complex in 2000. We also started building two new PTA plants in the Far East in China and Taiwan, which should commence operation in 2003. During the course of 2000, we announced development of a new technology for producing PTA, which will allow BP to substantially reduce capital and variable costs in new PTA plants as well as lowering emissions. Products PTA is important as a raw material for the manufacture of polyester; purified isophthalic acid (PIA) is used for isopolyester resins and gel coats; napthylene dicarboxylate is used for photographic film and specialized packaging. BP is the world's largest producer of PTA, with an interest in approximately 21% of the world's PTA capacity. PTA is manufactured at Cooper River, South Carolina and Decatur, Alabama, in the USA, Geel in Belgium, and Kuantan in Malaysia. We also produce PTA through joint ventures in Korea (BP 35%), Taiwan (BP 50%), Indonesia (BP 50%), Brazil (BP 49%) and Mexico (BP 8.55%). The joint venture site in Taiwan is the largest PTA production site in the world, followed by our Cooper River site which is the second largest. These two, together with the Korean joint venture and Decatur sites represent four of the five largest PTA production sites in the world. PIA is produced in Joliet, Illinois; Geel, Belgium; and by the AGIC joint venture (BP 50%) with Mitsubishi Gas Chemical Company in Japan. Napthylene dicarboxylate is produced at our plant in Decatur, Alabama. BP is one of the world's largest producers of paraxylene (PX) and metaxylene (MX), the feedstocks for PTA and PIA, respectively. PX and MX are produced from mixed xylene streams acquired from BP refineries and third party producers. The Aromatics and Derivatives business is fully integrated in using our manufactured paraxylene as feedstock for the production of our PTA product. Major Activities - -- BP's Korean PTA joint venture, Samsung Petrochemical Company Limited (SPC) (BP 35%) acquired Samsung General Chemicals (SGC) PTA plant (360 ktepa) in Korea at a cost of $220 million at the end of 2000. - -- Advanced manufacturing technology projects continued at Texas City and Decatur during 2000. These initial projects are the beginning of a broader plan to implement the introduction of leading edge process technology and control systems. This will create extensively automated facilities which are integrated with supply from the nearby refineries and demand from downstream products. - -- In Belgium, work was completed on a 420-ktepa PX unit at our Geel site costing $260 million Capital expenditure at this site in 2000 was $40 million, (1999 $100 million and 1998 $120 million). The unit was placed in service in April, 2000 and is based on our technology for PX crystallization incorporating new process and catalyst technologies first implemented at our Decatur site in 1997. - -- Two new PTA plants have started construction in China and Taiwan using BP's newly announced PTA technology. The Zhuhai (BP 80%) unit will add 350-ktepa capacity at a cost of $360 million, of which $50 million was spent in 2000. A new plant at our CAPCO joint venture in Taiwan (BP 50%) will add a further 700-ktepa capacity at a cost of $440 million. The new Zhuhai and CAPCO units are both expected to commence operation in the first half of 2003. - -- Expansion of the PTA plant at Cooper River is planned to begin in 2001. This will result in a 160 ktepa capacity addition to the plant which is expected to come on line in the first half of 2002. 49
Olefins and Polymers Our goal is to achieve a strong polymers market position. Through the Appryl dissolution we will acquire operational control of a polypropylene business. The proposed Solvay deals would increase our polypropylene business and our interests in global high density polyethylene (HDPE) and the additional 50% share of Erdoelchemie represents an increase of some 10% of our total chemicals production volumes. In addition to these business repositioning changes, we will continue with investments in our existing businesses. We will build on our existing technology base, for example, metallocene catalyst , the proprietary technology used in INNOVENE, our gas phase polyethylene production process. Our product portfolio is biased to differentiated products for example, HDPE and polypropylene, which will be further enhanced as a result of the above transactions. Our internal organization splits this business into two geographic regions; Europe, Africa and the Middle East and the Americas and Asia. Products We produce and market the basic petrochemical building blocks, known as feedstocks, that are used primarily as raw material for other chemical products. Feedstock chemicals are derived from the steam cracking of liquid and gaseous hydrocarbons. The olefins -- ethylene, propylene and butadiene -- are produced by crackers at Grangemouth, UK; Lavera, France (BP 50%); Dormagen, Germany by Erdolchemie (BP 50%) (to be increased to 100% in 2001); Chocolate Bayou, Texas; and Kertih, Malaysia (BP 15%). These crackers produce the raw materials for the production of derivative products including polyethylene, polypropylene, acrylonitrile, styrene, ethanol and ethylene oxide, which are also produced at various BP plants. The polymers product line includes polypropylene, used for moulded products, fibres and films; polyethylene, used for packaging, pipes and containers; and styrene polymers used in packaging and containers. We are the second-largest producer of polypropylene in the world. Polypropylene is manufactured at Chocolate Bayou and Cedar Bayou, Texas and Geel, Belgium. In addition, BP operates a new polypropylene plant at Grangemouth, UK commissioned during 2000 and from 2001 we have an interest in the manufacturing joint venture at Lavera, France. BP has its own proprietary polypropylene technology. We are one of Europe's leading producers and suppliers of polyethylene, the world's most widely used plastic. BP operates linear low density polyethylene (LLDPE) and HDPE plants at Grangemouth, Lavera, Merak in Indonesia (BP 51%) and at Kertih in Malaysia (BP 60%). A low density polyethylene (LDPE) plant is operated at Wilton, UK. Erdolchemie (BP 50%) also produces LLDPE and LDPE at Dormagen in Germany. We operate styrene monomer plants at Texas City, Texas in the USA and Marl in Germany. Polystyrene plants are operated at Marl and Wingles in France and Trelleborg in Sweden. Expanded polystyrene plants are operated at Wingles and Marl. Europe, Africa and Middle East -- Major Activities - -- In the UK, as part of completion of a major $825-million development programme, a 270-ktepa ethylene expansion at Grangemouth is scheduled for completion in the first quarter of 2001 at a total cost of $250 million Capital expenditure on this expansion in 2000 was $120 million (1999 $100 million and 1998 $20 million). When the expansion is complete, Grangemouth will have 1 million tonnes of ethylene capacity. This additional production will feed new plants both at Grangemouth and Hull, which are to be commissioned between the fourth quarter 2000 and the second quarter 2001. - -- As part of the Grangemouth expansion programme, a new 300-ktepa LLDPE polyethylene plant employing enhanced high productivity process technology was commissioned in December 2000 at a total cost of $220 million. Capital expenditure in 2000 was $70 million, (1999 $110 million and 1998 $40 million). As part of the programme, we are converting an existing LLDPE Plant at Grangemouth to HDPE manufacture. The converted plant is scheduled to be commissioned during second quarter of 2001 providing 30-ktepa of incremental polyethylene capacity. - -- The dissolution of the Appryl polypropylene joint venture with ATOFINA was completed in December 2000. - -- BP agreed in principle to purchase Bayer's 50% stake in Erdolchemie. - -- BP and Solvay announced in December 2000 that they have signed a memorandum of understanding aimed at strengthening their polymers businesses. 50
Americas and Asia -- Major Activities - -- Advanced manufacturing technology projects were started at Texas City and Chocolate Bayou. These initial projects are the beginning of a broader plan to implement the introduction of leading edge process technology and control systems. This will create extensively automated facilities which are integrated with supply from the refineries nearby and demand from the downstream products. - -- BP continued feasibility studies on a $2.7-billion joint venture project for an integrated ethylene cracker complex in China with the Shanghai Petrochemical Company. - -- Bataan Polyethylene Corporation, a joint venture in the Philippines between BP (38%), Petronas, Sumitomo and local Philippine shareholders successfully commissioned a 250-ktepa polyethylene plant during the fourth quarter of 2000. Intermediates As with Aromatics, we aim to be global number one or two in terms of market share in markets where we compete. New investments will build on existing leadership positions and distinctive technology, for example breakthroughs in butanediol manufacture. The divestment of the Fabrications businesses are consistent with our strategic aim of focusing the portfolio on a smaller range of global leading positions. Products These businesses add value to raw materials produced by our other chemicals businesses and include acetic acid and its derivatives; a range of solvents and industrial chemicals; linear alpha olefins; polybutenes; acrylonitrile; trimellitic anhydride (TMA), used by the automotive, construction, consumer goods, and packaging industries; butanediol (BDO), used in synthetic materials and engineering plastics; and maleic anhydride (MAN), used in a wide range of plastics and resins. This sector also includes the Fabrications businesses which are to be divested. We are a major supplier of acetic acid, a versatile chemical used in a variety of products such as foodstuffs, textiles, paints, dyes and pharmaceuticals. BP has acetyls operations in Europe, the USA, Korea (BP 51%), China (BP 51%) and a new 400-ktepa plant in Kertih, Malaysia (BP 70%) which was commissioned in the fourth quarter of 2000. In Korea, the Asian Acetyls Company (BP 34%) operates a 150-ktepa vinyl acetate monomer (VAM) plant. BP currently operates a 110-ktepa VAM plant at Baglan Bay, UK and has a toll manufacturing agreement with Enichem for 50 ktepa of VAM from Porto Marghera in Italy. A new 250-ktepa VAM plant is currently under construction at Hull, UK. This plant is due to be commissioned in the middle of 2001 and should lead to the subsequent closure of the Baglan Bay plant. BP is a leading supplier of polybutene which we manufacture at Texas City, Texas, and Whiting, Indiana and at Lavera, France. Polybutene is used in fuel additives, lubricants, adhesives, sealants, cable filling compounds, personal care products, in polymer modification, tackified polyethylene, explosives and in many other products. Linear alpha olefins (LAO) are used in the production of polyethylene, for the manufacture of plasticizers for polyvinyl chloride, to manufacture poly alpha olefins for synthetic lubricants, for the production of biodegradable surfactants, in synthetic-based drilling muds for the oil field and for a host of other intermediate and final products. LAO are produced at our facilities in Pasadena, Texas and Feluy, Belgium. BP is a leading supplier of poly alpha olefins, high viscosity index materials primarily used in the production of high performance, environmentally friendly, synthetic lubricants and motor oils. These materials are manufactured at our facilities in Deer Park, Texas and Feluy, Belgium. BP is the world's largest producer and marketer of acrylonitrile. We operate two acrylonitrile plants at Green Lake, Texas and Lima, Ohio. Green Lake, with a capacity of 460-ktepa, is the largest acrylonitrile production site in the world. Acrylonitrile is also produced by Erdolchemie at Dormagen, Germany and through a capacity rights agreement with Sterling Chemicals at Texas City, Texas. Additionally, BP is the world's largest producer and marketer of acetonitrile, primarily sold into pharmaceutical applications. The anhydride business unit produces TMA and MAN at Joliet, Illinois, and is the world's largest producer of TMA. In 2000, we entered the global market for BDO using our proprietary technology in a world-scale plant at Lima, Ohio. BDO and its derivatives are used in pharmaceuticals, a variety of personal care products, plastics, auto parts and sports clothing. 51
Major Activities - -- Construction is nearing completion on a 220-ktepa ethyl acetate plant at Hull and a 110-ktepa ethanol plant at Grangemouth at a combined cost of $200 million. Expenditure on these projects in 2000 was $110 million, (1999 $60 million and 1998 $10 million). These are scheduled for commissioning in the second and fourth quarter of 2001 respectively. The ethyl acetate investment is based on BP's innovative 'direct addition' method which uses ethylene and acetic acid and which does not require ethanol as a raw material. To supply ethylene to the new plants, a $70 million pipeline has been installed between Teesside and Hull, linking into the UK ethylene network. Capital expenditure on the pipeline was $40 million in 2000 (1999 $20 million and 1998 $10 million). - -- Construction continues on a $145-million, 250-ktepa VAM plant at Hull, which uses the proprietary BP LEAP technology based on fluid bed catalyst. Capital expenditure on this plant in 2000 was $80 million (1999 $40 million and 1998 $10 million). The work is scheduled for completion in the third quarter of 2001 and the plant will ultimately replace production from Baglan Bay and Porto Marghera and the Enichem toll manufacturing agreement. The capacity of the new plant is planned to increase to 300-ktepa in 2002/3. - -- In the fourth quarter of 2000, construction finished and a new BDO plant was started at Lima in the USA. The new line has a capacity of 70 ktepa and cost $160 million. Capital expenditure on the plant was $50 million in 2000 (1999 $90 million and 1998 $20 million). - -- Construction of a $300-million, 250-ktepa LAO facility in Alberta, Canada is also nearing completion. It is scheduled to come online during mid-2001. Capital expenditure on the plant in 2000 was $170 million (1999 $90 million and 1998 $30 million). - -- During 2000, we sold the phathallic anhydride and phthalates businesses to Lonza SpA. As a result, the manufacturing units at our Hull site will be shutdown during 2001. - -- In early 2001, we announced our intention to divest the Fabrications businesses, targeted to happen in 2001. - -- We announced in January 2001 our intention to build a new 65-ktepa TMA plant at our existing PTA complex in Kuantan, Malaysia. The plant will use our newly developed proprietary process technology. The $150 million TMA plant is expected to be completed by the end of 2002 and will double our total TMA capacity to 130-ktepa. 52
OTHER BUSINESSES AND CORPORATE Other Businesses and Corporate comprises Finance, BP Solar, the Group's coal asset and aluminium asset, its investments in PetroChina and Sinopec, interest income and costs relating to corporate activities worldwide. <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ----- ----- ----- ($ million) <S> <C> <C> <C> Turnover (a)............................................. 249 198 199 Total replacement cost operating loss.................... (1,110) (826) (374) Total assets............................................. 11,970 2,643 3,516 Capital expenditure and acquisitions..................... 30,616(a) 284 501 - ---------- </TABLE> (a) Capital expenditure and acquisitions includes $27,506 million for the acquisition of ARCO and $994 million for the acquisition of interests in PetroChina and Sinopec. Finance co-ordinates the management of the Group's major financial assets and liabilities. From locations in the UK, Europe, the USA and the Asia Pacific region, it provides the link between BP and the international financial markets, and makes available a range of financial services to the Group including supporting the financing of BP's projects around the world. Moody's and Standard and Poor's have assigned long-term debt ratings of Aa1 and AA+, respectively, to BP. Finance has in place a Debt Issuance Programme, under which the Group may raise an aggregate of $6 billion of debt for maturities of one month or longer. At March 30, 2001 the amount drawn down against this programme was $2,237 million. BP Solar. In 2000 we renamed our Solar business from BP Solarex to BP Solar. Our solar energy business increased production and shipments by 31% compared with 1999, selling a total of 42 megawatts (MW) of solar panel generating capacity (1999, 32MW and 1998, 27MW). High-profile projects included the USA's largest solar housing project in Los Angeles and installation of solar panels to power apartments in the athletes' village at the Sydney Olympic Games. In 2000, we converted 200 BP service stations worldwide to solar power. Coal activity consists of our 50% interest in PT Kaltim Prima Coal, an Indonesian company. This company operates an opencast coal mine at Sangatta in Kalimantan, Indonesia. Aluminium is a non-integrated producer and marketer of rolled aluminium products, headquartered in Louisville, Kentucky, USA. Production facilities are located in Logan County, Kentucky and are jointly owned with Alcan Aluminum. The primary activity of our aluminium business is the supply of aluminium coil to the beverage can business. Research, technology and engineering activities are carried out by each of the major business streams on the basis of a distributed programme coordinated by the BP Technology Council. This body provides leadership for scientific, technical and engineering activities throughout the Group and in particular promotes cross-business initiatives and the transfer of best practice between businesses. In addition, a group of eminent industrialists and academics form the Technology Advisory Council, which advises senior management on the state of technology within the Group and helps identify current trends and future developments in technology. Research and development is carried out using a balance of internal and external resources. Involving third parties in the various steps of technology development and application enables a wider range of technology solutions to be considered and implemented, improving the productivity of research and development activities. The innovative application of technology and the rapid transfer of this knowledge through the Group make a key contribution to improving BP's business performance, particularly in the areas of the introduction of new products, safety, the environment, cost reduction and efficiency of business operations. We believe that, in addition to improving existing business performance, the use of innovative technology can create new possibilities for the organic growth of our energy- and petrochemical-related businesses. Insurance. The Group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the Group. Losses will therefore be borne as they arise, rather than being spread over time through insurance premia with attendant transaction costs. The position will be reviewed periodically. 53
REGULATION OF THE GROUP'S BUSINESS United Kingdom Licensing. Pursuant to, among other things, the Petroleum (Production) Act 1934, all petroleum existing in its natural condition in strata in the UK or beneath its territorial waters (including its continental shelf) is the property of the Crown, and licences to explore for and produce it may be granted, subject to conditions, by the Secretary of State for Trade and Industry (Secretary of State). These conditions include provisions relating to the term of the licence, the imposition of specific drilling obligations, environmental protection controls, controls over the development and decommissioning of oil and natural gas fields (including restrictions on production) and the payment of royalties. Development of oil and natural gas reserves. The development and production of UK oil and natural gas reserves (including rates of production) require the approval or consent of the Secretary of State. There have been a number of policy statements by various UK Governments over the years with respect to production controls. Although successive Governments have made it clear that the imposition of production cut-backs in order to facilitate a coherent depletion policy has been kept under review, the steps taken by the Government since the early 1980s have tended to concentrate on encouraging exploration, development and production and no significant cut-backs of previously agreed rates of production are known to have been imposed. Other controls. In addition to the regulatory powers of the Government referred to above, the Secretary of State has wide powers over the oil field operations, including gas flaring, the installation, use and tariffs of sub-marine pipelines, the construction or expansion of refining capacity and powers to impose programmes for the eventual decommissioning of offshore installations. Furthermore, the Secretary of State for Transport has powers to control the positioning of offshore installations if the chosen location is in or is close to a shipping lane. The UK Health and Safety Executive has wide powers and duties in relation to offshore health and safety. BP is also subject to European Union legislation, in particular the Procurement Directive which regulates the procedure for awarding major contracts. Petroleum revenue tax. Petroleum revenue tax (PRT) was abolished in the Finance Act 1993 in respect of oil and natural gas fields given development consent on or after March 16, 1993 (Non-Taxable Fields). Profits from Non-Taxable Fields are charged to corporation tax under general principles. PRT is still charged on profits from fields given development consent before that date (Taxable Fields). PRT is charged in relation to Taxable Fields on profits from oil (which includes gas except where specifically excluded by statute) won under licences granted under either the Petroleum (Production) Act 1934 or the Petroleum (Production) Act (Northern Ireland) 1964. It is charged on a field-by-field basis, at the rate of 50% for chargeable periods ending after June 30, 1993 (75% for periods ending on or before that date), on the assessable profit arising in each chargeable period (normally the six months ending on June 30 and December 31 in each year), as reduced by any allowable losses and by an oil allowance (unless the maximum amount of oil allowance has already been used), and subject in certain years to an overall limit (safeguard). PRT is also chargeable on any consideration received in connection with the use by other fields and the disposal of certain 'qualifying assets', the expenditure on which is allowable for PRT, subject to an allowance in the case of the use of assets by fields which are themselves liable to PRT. The assessable profit reflects, very broadly, the market value of oil won less the costs of discovery and production, including any Government royalties payable. Interest and other financing costs are not deductible in determining the assessable profit; instead, certain costs are designated as qualifying for a supplement of 35% (uplift). Uplift ceases for costs incurred after the end of the chargeable period in which the field's cumulative income exceeds its cumulative expenditure (payback). Oil allowance exempts certain amounts from PRT. For each onshore field and offshore field given development consent before April 1982, an allowance of up to 250,000 tonnes of oil per chargeable period is available, subject to a cumulative total of 5 million tonnes. For each onshore field and each offshore field situated in the Southern Basin of the North Sea given development consent after March 1982, the oil allowance for chargeable periods ending after June 30, 1988 is 125,000 tonnes per chargeable period and the cumulative total is 2.5 million tonnes. For each offshore field not situated in the Southern Basin given development consent after March 1982, the allowance is 500,000 tonnes per chargeable period subject to a cumulative total of 10 million tonnes. The oil allowance is shared by the participants in each field in proportion to their shares of oil. Safeguard provides that the total PRT payable in respect of a field is limited to 80% of the amount (if any) by which the PRT profits for a chargeable period (specially adjusted for this purpose) exceed 15% of accumulated expenditure (as adjusted). Safeguard remains available after payback has been reached for half as many periods again as it took to reach payback from the first chargeable period. 54
Allowable losses in any chargeable period can be set off against the assessable profits of subsequent or, after making an appropriate claim, previous periods from the same field but, in relation to losses arising in respect of chargeable periods ending after June 30, 1993, the PRT repayment plus any interest thereon arising from the set-off of losses against profits of previous periods cannot exceed 60% of the losses set off (85% in respect of chargeable periods ending after June 30, 1991 and on or before June 30, 1993). In addition, relief is available against the assessable profit from a field for certain expenditure incurred outside the field. There are restrictions to prevent the obtaining of relief for expenditure incurred in connection with Non-Taxable Fields against profits from Taxable Fields. Exploration or appraisal expenditure incurred on or after March 16, 1983 and before March 16, 1993, in respect of an area for which no development decision has been made, may be set against the assessable profits of any Taxable Field together with any such expenditure incurred prior to that date which is designated as abortive. There is no relief for exploration and appraisal incurred after March 16, 1993 unless the Company was already committed to it at that date and it is incurred on or before March 16, 1995. There is an additional transitional relief for exploration and appraisal expenditure, subject to certain conditions, limited to a maximum of (pound)10 million for expenditure incurred on or after March 16, 1993 and before January 1, 1995. Finally, a loss from a Taxable Field in which the winning of oil has permanently ceased which cannot be relieved against the assessable profits of that field can be claimed against the assessable profit from any other Taxable Field. The offset of reliefs is limited to prevent a company buying into mature oil fields and setting pre-acquisition expenditures against the assessable profits of that field. Corporation tax. Companies are also subject to corporation tax on their profits or gains from oil extraction activities, although PRT is deductible in computing any corporation tax liability. There are restrictions on using reliefs from other activities against profits or gains from oil extraction activities, or from the disposal of interests in oil or of assets used in connection with a field in the UK or a designated area. There is also an exemption from capital gains taxation and capital allowance clawback for certain exchanges of licence interests before the development stage. An election can be made in relation to expenditure incurred after June 30, 1991 for 100% reliefs for certain net offshore decommissioning expenditure. Losses created by these decommissioning reliefs are available for set-off against profits of the previous three years. United States Tax. The State of Alaska imposes various taxes on the Group's operations in Alaska. At present, these include a severance tax on oil and natural gas produced, an ad valorem tax on all oil and gas exploration, production and pipeline equipment and a corporate income tax on companies doing business in Alaska. Following the Exxon Valdez oil spill, the State of Alaska passed an act to finance the State's Oil and Hazardous Substance Release Response Fund by imposing a conservation surcharge of $0.05 per barrel on all oil subject to the State's oil and gas properties production tax. Subsequently, the State amended the surcharge to suspend $0.02 per barrel of it when the balance in the Response Fund exceeds $50 million, and as a result the net surcharge is $0.03 per taxable barrel unless there is a spill that draws the Fund's balance below $50 million. Further, losses occurring in connection with a catastrophic oil discharge are not deductible as business expenses in determining the gross value of oil for tax purposes in the State of Alaska. Pipeline regulations. The Interstate Commerce Act requires common carriers engaged in the transport by pipeline of oil in interstate or foreign commerce to file tariffs with the Federal Energy Regulatory Commission (FERC) showing all rates, classifications, rules and practices between all points on their system. It also prohibits them from collecting any different compensation for transportation from that specified in their approved tariffs. Third parties, or the FERC on its own motion, may initiate an investigation of any proposed tariff, which involves the scheduling of a hearing. If the FERC, at the conclusion of a hearing, finds that a new or increased rate is unreasonable or discriminatory, or otherwise in violation of the Interstate Commerce Act, it may order the carrier to cease and desist from charging that rate, may prescribe a rate for the future and order refunds to shippers of collected amounts found to be unreasonable. Similar corresponding provisions at a state legislative level and enforced through a state regulator may also apply to common carriers engaged in the transport by pipeline of oil in intrastate commerce. 55
ENVIRONMENTAL PROTECTION Health, Safety and Environmental Regulation The Group is subject to numerous national and local environmental laws and regulations concerning its products, operations and activities. These laws and regulations may require the Group to remediate or otherwise redress the effects on the environment of prior disposal or release of chemicals or petroleum substances by the Group or other parties. Such contingencies may exist for various sites including refineries, chemicals plants, gas processing plants, oil fields, service stations, terminals and waste disposal sites. In addition, the Group may have obligations relating to prior asset sales or closed facilities. Provisions for environmental restoration and remediation are made when a clean-up is probable and the amount is reasonably determinable. Generally, their timing coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provisions made are considered by management to be sufficient for known requirements. The extent and cost of future environmental restoration, remediation and abatement programmes are inherently difficult to estimate. They depend on the magnitude of any possible contamination, the timing and extent of the corrective actions required and BP's share of liability relative to that of other solvent responsible parties. Though the costs of future restoration and remediation could be significant, and may be material to the results of operations in the period in which they are recognized, it is not expected that such costs will have a material impact on the Group's financial position or liquidity. The Group's operations are also subject to environmental and common law claims for personal injury and property damage caused by the release of chemicals or petroleum substances by the Group or others. Proceedings instituted by governmental authorities are pending or known to be contemplated against BP and certain of its US subsidiaries under US federal, state or local environmental laws, each of which could result in monetary sanctions in excess of $100,000. No individual proceeding is, nor are the proceedings as a group, expected to have a material adverse effect on BP's consolidated financial position or profitability. Management cannot predict future developments, such as increasingly strict requirements of environmental laws and enforcement policies thereunder, that might affect the Group's operations or affect the exploration for new reserves or the products sold by the Group. A risk of increased environmental costs and impacts is inherent in particular operations and products of the Group and there can be no assurance that material liabilities and costs will not be incurred in the future. In general, the Group does not expect that it will be affected differently from other companies with comparable assets engaged in similar businesses. Management believes that the Group's activities are in compliance in all material respects with applicable environmental laws and regulations. For a discussion of the Group's environmental expenditures see Item 5 - Operating and Financial Review and Prospects - Environmental Expenditure. In December 1997, at the Third Conference of the Parties to the United Nations Framework Convention on Climate Change in Kyoto, Japan, the participants agreed on a system of differentiated internationally legally binding targets for the first commitment period of 2008-2012. The range of targets in Annex I countries (OECD, former Soviet Union and Eastern Bloc countries) against 1990 levels of emissions is from -8% to +10% for a basket of the six main greenhouse gases. The USA agreed, subject to ratification by the Senate, on a reduction of 7%, and the European Union on a reduction of 8%. EU member states have undertaken differentiated commitments on the basis of 'burden sharing' to meet the overall Community target. If these targets are to be met, a major reduction in the use of fossil fuels would be required, and this would be likely to have a significant effect on BP's main businesses. However, the Group does not expect that it will be affected differently from other companies with comparable assets engaged in similar businesses. At the Sixth Conference of the Parties to the United Nations Framework Convention on Climate Change held in the Hague in November 2000, national governments failed to reach agreement on the rules and mechanisms for delivery of the greenhouse gases reduction targets. The issue remains under debate and international negotiations will continue in 2001. The following is a summary of significant health, safety and environmental legislation affecting the Group in 2000. 56
United States The Clean Air Act and its regulations require, among other things, enhanced monitoring of major sources of specified pollutants, stringent air emission limits on chemical plant, refinery, marine and distribution terminal emissions, risk management plans for storage of hazardous substances, and new fuel specifications. Title V of the Clean Air Act requires major emission sources to obtain new air permits. This permitting effort is underway at the Group's US operations. Title V also requires more comprehensive measurement of specified air pollutants from major emission sources. Two aims of this regulation are to provide regulating bodies with accurate data on emissions from major sources, and to enable regulatory authorities to better evaluate compliance with applicable emission limitations. Federal authorities have recently promulgated monitoring requirements. Risk Management Plan regulations require that any non-exempted facility that processes or stores a threshold amount of a regulated substance prepares and implements a risk management plan to detect, prevent and minimize accidental releases. Undertaking an offsite hazard assessment, preparing a response plan and dialogue with the local community are the primary components of the programme. Additionally, the Clean Air Act imposes specifications for motor vehicle fuels that significantly impact petroleum refining and marketing operations. In nine urban areas with the highest ozone levels, reformulated gasoline (RFG) containing oxygenates and lower levels of benzene, and having lower levels of volatility, was introduced beginning January 1995. The emission reduction requirements have been phased in over time and are now fully in effect. BP manufactures and markets fuels in some of these nine areas, as well as in other areas that chose to join the RFG programme. Since 1992, gasoline sold during the winter in approximately 40 metropolitan areas with high carbon monoxide levels must have higher levels of oxygenates such as methyl-tertiary-butyl-ether (MTBE) and ethanol. BP is providing such oxygenated fuels in a number of US markets. Recently some environmental groups and legislators have expressed opposition to the continued use of MTBE as an oxygenate. California has recently banned the use of MTBE due to contamination and public health concerns and other states and the US Environmental Protection Agency (EPA) have either passed or are considering legislation to restrict or eliminate the use of MTBE. Some metropolitan areas have been able to achieve compliance with carbon monoxide standards and terminate their oxygenated fuels programmes. At the end of 1999, the EPA promulgated its Tier 2/Gasoline Sulphur Programme. This programme will impose new tailpipe emission standards on all passenger vehicles while lowering the allowable gasoline sulfur content. These standards will be phased in from 2004 to 2007. Beginning 1993, the Clean Air Act limited highway diesel fuel sulphur content to 500 parts per million. BP has been producing this fuel in many of its US markets. The Amendments also require service stations located in certain ozone non-attainment areas to install equipment to capture gasoline vapours released during refuelling. At the end of 2000, the EPA adopted rules reducing diesel sulphur limits to 15 parts per million. These rules will take effect in 2006. Both the new gasoline rules referred to above and diesel rules will require additions or upgrades to current refining facilities. The Clean Air Act also requires installation of 'maximum achievable control technology' (MACT) over a ten-year period at certain types of industry facilities that release certain specified toxic chemicals. Additional controls could be required if the EPA determines that an unacceptable residual risk remains after installation of MACT. The EPA has finalized MACT control requirements for certain categories of chemical plants, refineries, gasoline marketing terminals and marine terminals. Additional regulations on some sources in petroleum refineries were proposed in 1998. These are expected to be finalized in 2001 with compliance required in 2004. In order to comply with the National Ambient Air Quality Standards, which were promulgated to protect public health, some States will be requiring large reductions in the emission of Nitrogen Oxides, which will require the addition of controls on some refineries and chemical operations in the US. In addition to these required reductions, during the year 2000, BP reached an agreement in principle with the EPA and several states that would settle alleged violations of various Clean Air Act requirements. A Consent Decree was finalized in early 2001. This settlement, which largely addresses emissions of sulphur dioxide and nitrogen dioxide, requires the installation of additional controls at all eight of BP's US refineries at a cost, over an eight-year period, of approximately $500 million, and the payment of a $10 million penalty. These costs will be accounted for in line with BP's accounting policy for environmental expenditure. 57
BP is also in the second year of implementing a plea agreement with the US Justice Department to develop, implement and maintain a nationwide environmental management system (EMS) consistent with the best environmental practices at all Group facilities engaged in oil exploration, drilling and/or production in the US and its territories. This programme is expected to cost approximately $15 million. The Clean Water Act regulates the discharge of wastewater and other pollutants into US waters. Facilities are required to obtain permits for most discharges, install control equipment and implement operational controls and preventative measures. Requirements under the Clean Water Act have become more stringent in recent years, including coverage of storm and surface water discharges at many facilities and increased control of toxic discharges. The administrators of agencies for the Clean Water Act and the Endangered Species Act formalized agreements linking those statutes with the potential to limit access because of habitat concerns to certain areas with development potential. During 1995 a final federal rule was issued regarding protection of the Great Lakes watershed which will have local and national impacts on water protection requirements. In July, 2000, EPA promulgated a new rule that would impose total maximum daily limits (TMDLs) on discharges that would impair achievement of water quality objectives in many waterways. The US Congress did not provide EPA with funding to implement the rule, but work on TMDLs is ongoing under an earlier rule and new, more stringent limits on discharges from industrial facilities are expected to result in the future. The Oil Pollution Act of 1990 (the Oil Pollution Act) significantly increased oil spill prevention requirements, spill response planning obligations and spill liability for tank vessels (tankers and barges) transporting oil, offshore facilities (such as platforms) and onshore terminals. To provide funds for response to and compensation for oil spills when the spiller is unable to do so, the Oil Pollution Act created a $1 billion fund which is funded by a tax on imported and domestic oil. The Oil Pollution Act requires that all new tank vessels operating in US waters have double hulls, and began the phasing out, between the years 1995 and 2015, of existing vessels without double hulls. Oil transporters, terminals and other handling facilities are most affected by the expanded technical and operational requirements under OPA 90. Regulations require businesses to provide certificates of financial responsibility and to maintain facility response plans that, among other things, identify and prepare for worst case spill scenarios. Owners and operators of covered facilities and vessels must also conduct emergency response training, consistent with regulations and with area and national contingency plans. The Prince William Sound port-specific vessel escort plan required by regulations that became effective late in 1994, was updated during 1995, including operational requirements such as enhanced tanker steering capabilities, rudder failure response procedures, and reduced speed in the Valdez Narrows, plus directives on communications and training. BP has set performance objectives to enhance emergency preparedness and crisis management at all facilities, and to assure compliance with all related laws such as the Oil Pollution Act. These objectives are designed to be met through appropriate assessment, planning, training and routine exercises, and by the provision or identification of sufficient human and physical resources. BP has established a National Strike Team, the BP Americas Response Team, which consists of approximately 200 trained emergency responders at company locations throughout North America, which is ready to assist in a response to a major incident. The Resource Conservation and Recovery Act (RCRA) regulates the storage, handling, treatment, transportation and disposal of hazardous and non-hazardous wastes. It also requires the investigation and remediation of certain locations at a facility where such wastes have been previously released or disposed of. RCRA requirements have become increasingly stringent in recent years, as the EPA expands the definition of hazardous wastes. BP facilities generate and handle a number of wastes regulated by RCRA and have units that have been used for the storage, handling or disposal of RCRA wastes that are subject to investigation and corrective action. Under the Comprehensive Environmental Response, Compensation, and Liability Act (also known as CERCLA or Superfund), waste generators, site owners, facility operators and certain other parties may be strictly liable for part or all of the cost of addressing sites contaminated by spills or waste disposal regardless of fault. Additionally, most states have laws similar to CERCLA. A federal tax on oil and certain chemical products was enacted to fund a large part of the CERCLA programme but this tax has been suspended for several years while CERCLA reform legislation is debated in the US Congress. BP has been identified as a Potentially Responsible Party (PRP) under CERCLA and similar state statutes at 441 sites. A PRP has a joint and several liability for site remediation costs and so BP may be required to assume, among other costs, the share attributed to insolvent, unidentified or other parties. BP is the PRP identified as having the most significant exposure for remediation costs at 28 of these sites. For the remaining sites the number of PRPs ranges generally from 20 to 200. BP expects its share of remediation costs at these sites to be small. BP has estimated its potential exposure at all sites where it has been identified as a PRP and has accrued provisions accordingly. BP does not anticipate that its ultimate liability at these sites individually, or in aggregate, will be significant. 58
In addition to the number of active sites described above, ARCO, which was acquired by BP in April 2000, is currently involved in environmental assessments and clean-ups under these laws at federal- and state-managed sites, as well as other clean-up sites, including service stations, refineries, terminals, third party landfills, former nuclear processing facilities, sites associated with discontinued operations and sites that were formerly owned by ARCO and/or its predecessors. This comprises 148 sites for which ARCO has been named a PRP, along with other sites at which no claims have been asserted. Pursuant to the authority provided under Superfund, the State of Montana has pursued claims against ARCO for compensation for damage to natural resources allegedly caused by ARCO's predecessors' mining and mineral processing activities. In addition, two tribes were granted a limited form of intervention in the lawsuit, Montana vs. ARCO. The tribes, as alleged trustees, asserted claims against ARCO for alleged injury to and loss of natural resources located in the Clark Fork River Basin in southwest Montana. The United States Department of Interior also stated an intention to make a claim for natural damages in the Clark River Basin. These matters were settled in part in 1999, however, remaining for disposition are the State's claims for $206 million for restoration damages at several sites. On June 23, 1989, the EPA filed a CERCLA cost recovery action against ARCO in the United States District Court for the District of Montana, for the oversight costs at several of the Upper Clark Fork River Basin Superfund sites. Litigation is proceeding on both the EPA's and ARCO's counterclaims against various federal agencies. In the counterclaims, ARCO seeks contributions from the federal agencies for remediation costs and for any natural resource damage liability ARCO might incur in Montana vs. ARCO. The settlements in Montana vs. ARCO, described above, resolved the claims and counterclaims in US vs. ARCO pertaining to one significant site and may provide a framework for possible future settlement of the remaining claims. The Group is also subject to claims made for natural resource damage (NRD) under several federal and state laws. This is a developing area under US law which could significantly impact the cost of some cleanups. NRD claims have been asserted by government trustees against several refineries and other company operations. Other significant legislation includes the Toxic Substances Control Act which, among other things, regulates the development, testing, import, export and introduction of new chemical products into commerce; the Occupational Safety and Health Act which, among other things, imposes workplace safety and health, training and process standards to reduce the risks of chemical exposure and injury to employees; and the Emergency Planning and Community Right-to-Know Act which requires emergency planning and spill notification as well as public disclosure of chemical usage and emissions. The Occupational Safety and Health Administration's Process Safety Management rule formalizes the procedures used in identifying and minimizing safety risks at facilities that use certain chemicals in excess of threshold quantities and also in conducting formal documented hazard reviews of all covered processes. In 1993 the South Coast Air Quality District (AQMD), which sets air quality standards for a five country area of Southern California, including Los Angeles County, adopted regulations requiring phased reductions of certain pollutants. By 2003, our Los Angeles refinery will be required to achieve cumulative reductions from 1992 level of oxides of nitrogen of 63% and oxides of sulphur of 83%. AQMD has created a pollution credits scheme, of which we take advantage as part of our plan to achieve the requisite levels of emission reductions. United Kingdom and European Union Part 1 of the UK Environmental Protection Act 1990 introduced the concept of Integrated Pollution Control (IPC) of pollution to air, water and land by requiring each prescribed process (including petroleum and gasification processes) to be authorized. The controls apply to new processes in England and Wales from April 1, 1991 and in Scotland from April 1, 1992. The standard to be achieved by each process is the Best Available Techniques Not Entailing Excessive Cost (BATNEEC). Existing petroleum and gasification processes had to apply for an IPC authorization by June 30, 1992. These processes were to be upgraded to the BATNEEC standard at the earliest opportunity and generally for petroleum and gasification processes by April 1, 1998. BP has registered all sites affected by the IPC legislation and is carrying out monitoring and upgrading of processes as required. Onshore oil production facilities are covered by separate guidance notes issued in November 1995. BP has IPC authorizations for its onshore production facilities which effectively equate to BATNEEC compliance. Where they do not, the authorization includes an agreed improvement programme which BP is working towards with its Environment Agency IPC Inspector. The UK Environmental Protection Act may also impose new investigation and remediation obligations on the Group's UK facilities upon the adoption of implementing regulations. 59
A European Commission directive for a similar system of Integrated Pollution Prevention and Control (IPPC) is based upon ensuring environmental quality standards are not exceeded and the application of Best Available Techniques (BAT) taking into account cost-benefit analysis as a holistic approach. In the event that the use of BAT will fail to meet Environmental Quality Standards (EQS), plant emissions must be reduced further to meet the EQS. This encompasses, among other things, most activities and processes undertaken by the oil industry within the European Union. The European Commission has stated that it hopes that all processes to which it applies will be licensed by July 2005. When implemented, this directive will replace the IPC regulation in the UK. All plants must be upgraded to BAT standards by 2007. The European Union Large Combustion Plant Directive sets emission limit values for sulphur dioxide, nitrogen oxides and particulates from large combustion plants; it also requires phased reductions in emissions from existing large combustion plants. Implementation by Member States was required by June 1990. In the UK, it has been given effect through the authorization mechanism in Part 1 of the Environmental Protection Act 1990. Large combustion plants required an IPC application to be made by April 30, 1991. Upgrading to the BATNEEC standard is required at the earliest opportunity, at the latest by April 1, 2001. The European Commission has considered proposals to impose emission limit values on small combustion plants. A revised Large Combustion Plant Directive was proposed by the Commission in 1998 to be considered by the Council and Parliament during 1999-2000, as part of the EU Acidification Strategy. After revisions of the EU treaty agreed to in Amsterdam, Parliament has acquired an increased role in environmental legislation through co-decision procedures. As part of its overall programme to combat air pollution, the European Union has set stringent emission limits for new cars and commercial vehicles which are being implemented in stages. Beginning October 1994, the sulphur content of diesel fuel was limited to 0.2% and from October 1996 the limit was further reduced to 0.05%. Heating oils were initially limited to 0.2% with further reductions subject to review. In August, the Federal German Government adopted a regulation to encourage early introduction of low sulphur transport fuels by setting differential excise taxes for gasoline and diesel with maximum 50 ppm sulphur content from November 2003, and for a maximum of 10 ppm from January 2001. It also proposed that 10 ppm sulphur fuels should be adopted at EU level. Implementation of the German regulation depends on tax derogations being agreed by the Commission and the other member states. The Commission made it clear that it will not consider 10ppm sulphur fuels within the current Auto/Oil Programme for implementation in 2005. In 1998, the EU adopted directives to set emission limits for cars and light vehicles to apply from 2000, together with specifications for gasoline and diesel fuel to apply from that date. Some member States indicate that they need such energy product taxes to enable them to meet their Kyoto commitments, within the EU burden sharing agreement, and are already implementing national legislation. The Commission is also undertaking a second Auto/Oil Programme to propose changes to other gasoline and diesel fuel specifications from 2005, as well as non-technical measures designed to help meet air quality targets. In April 1999, the EU adopted a directive to further reduce the sulphur content of liquid fuels, but excluding marine bunker fuel oil, and marine gas oil used by ships crossing a frontier between a third country and an EU Member State. Sulphur in gas oil will be limited to 0.2% from July 2000, and 0.1% from January 2008. From January 2003, sulphur in heavy fuel oil will be limited to 1%, except where use of heavy fuel oil up to 3% sulphur can be used in combustion plants without exceeding specific emission limits, and provided that local air quality standards are met. As part of its overall approach to improving air quality, in 1997 the Commission proposed its Acidification Strategy, and followed this with its proposal for a strategy to combat tropospheric ozone. The Ozone Strategy was adopted in 1998. Four air quality targets have been adopted as Directives, two more have been proposed by the Commission and a target of 120 micrograms per cubic metre for ozone itself was proposed in 1999, together with a proposal for national emission ceilings for the main polluting emissions. Upon adoption by the Council, these targets and ceilings will be the reference point for further environmental controls of industrial installations at Community and Member State levels. The carbon monoxide and benzene directive is the 2nd daughter Directive of 96/62/EC on ambient air quality assessment and management and prescribes, among other things, limit values and alert thresholds for carbon monoxide (CO) and benzene. For benzene, a limit value of 0.005 mg/m3 averaged over a calendar year applies. A margin of tolerance of 100%, to be progressively eliminated from 2003 to 2010, would apply. For carbon monoxide, a limit value of 10 mg/m(3) will apply with a rolling 8-hour averaging period and a 50% margin of tolerance on entry into force, to be reduced to zero from 2003 to 2005. 60
As part of its ozone strategy, the EU has taken action on volatile organic compounds (VOCs). In late 1994, the European Union adopted the so-called Stage 1 VOC controls which require a 90% cut in emissions over ten years from petrol transport and storage. In November 1996, the Commission proposed a directive on control of emissions of organic solvents from the solvent-using industry which has the goal of combating low-level ozone by setting emission limits and, as an alternative, targets to be met by national plans. Existing installations would be required to reach compliance by 2007. This proposal was adopted as a Directive during 1998. As part of a package to stabilize carbon dioxide emissions at 1990 levels by the year 2000, the European Commission proposed a combined carbon dioxide energy tax. In March 1997, the Commission proposed instead an energy tax that is intended to be fiscally neutral when applied by Member States. Though formally the proposal replaces the carbon dioxide energy tax proposal that had been blocked in Council, it has as its main objective to provide a harmonized framework by setting minimum levels for national excise taxes on energy products, and to allow Member States greater flexibility to offer tax incentives based on environmental criteria, whilst avoiding barriers to trade within the Single Market. Maximum sulphur levels for gasoline and diesel fuels to apply from 2005 were also agreed as 50 parts per million, which is 0.005% , and 35% maximum aromatic content for gasoline from the same date. In 1999, this was followed by emission limits for heavy commercial vehicles, also based on the Auto/Oil Programme conclusions. The Commission will make further proposals during 2001 based on the results of its Auto/Oil II Programme and the review of the sulphur content of gasoline and diesel undertaken in parallel. The European Union enacted the Major Hazards Directive in 1982. The intention of this legislation is to identify industrial sites which have the potential to suffer a major accident which would impact on the neighbouring population. Such sites are defined by the hazards that exist on them, in some cases by the process in operation, but mainly by exceeding the defined threshold quantities of various categories of 'dangerous substances' in storage or use on the premises. It is the responsibility of the site to evaluate their hazards. Those which fall into the category of a major hazard site must produce a safety case which contains the evaluation of the hazards, an assessment of the consequences of the most serious credible incidents which can occur, both on and off site, and a description of the emergency plan which they have in place to deal with them. The safety case must be submitted to the national regulator, who acts on behalf of the local authority. The site is also expected to communicate the relevant aspects of its emergency plan to the local community. All BP sites in Europe are in compliance with the Major Hazards Directive as enacted in each specific country. The European Union has now adopted a revised Major Hazards Directive known as the Control of Major Accident Hazards Regulation, which came into force in February 1999. The main objective of this revision is to ensure that effective safety management systems are in place and that potential environmental impacts that could arise from accidents are properly assessed and appropriate provisions are implemented by the operator. The European Commission is committed to a harmonized EU approach to liability for environmental damage. This follows a 'green (discussion) paper' in 1992 that focused on a strict liability approach. The Commission intends to publish a draft for consultation by mid 2001. The UK Offshore Safety Act 1992 came into force on March 6, 1992. Detailed implementation is through regulations made under existing health and safety legislation enforced by the UK Health and Safety Executive. The Offshore Installations (Safety Case) Regulations 1992 came into force in May 1993. BP submitted all safety cases by the required date of November 1993. This included 22 operational safety cases, all of which have been accepted, and two design safety cases on new installations. As part of the safety case, BP was required to justify continued operation and outline remedial measures identified as part of the risk assessment completed. Work on these remedial works was completed by the November 1995 deadline. PROPERTY, PLANTS AND EQUIPMENT BP has freehold and leasehold interests in real estate in numerous countries throughout the world, but no one individual property is significant to the Group as a whole. See Item 4 -- Information on the Company for a description of the Group's significant reserves and sources of crude oil and natural gas. Significant plans to construct, expand or improve specific facilities are described under each of the business headings within this Item. 61
ORGANIZATIONAL STRUCTURE The significant subsidiary and associated undertakings and joint ventures of the Group at December 31, 2000 and the Group percentage of equity capital or joint venture interest (to nearest whole number) are set out below. The principal country of operation is generally indicated by the company's country of incorporation or by its name. Those held directly by the Company are marked with an asterisk (*), the percentage owned being that of the Group unless otherwise indicated. <TABLE> <CAPTION> Subsidiary Country of undertakings % incorporation Principal activities - ------------ ------------- -------------------- <S> <C> <C> <C> International BP Chemicals Investments 100 England Chemicals BP Exploration Co. 100 Scotland Exploration and production BP International 100 England Integrated oil operations BP Oil International 100 England Integrated oil operations BP Shipping* 100 England Shipping Burmah Castrol 100 England Lubricants Europe UK BP Amoco Capital 100 England Finance BP Chemicals 100 England Chemicals BP Oil UK 100 England Refining and marketing Britoil (parent 15%)* 100 Scotland Exploration and production Jupiter Insurance 100 Guernsey Insurance France BP France 100 France Refining and marketing and chemicals Germany Deutsche BP 100 Germany Refining and marketing and chemicals Netherlands BP Capital BV 100 Netherlands Finance BP Nederland 100 Netherlands Refining and marketing Norway BP Amoco Norway 100 Norway Exploration and production Spain BP Espana 100 Spain Refining and marketing Middle East Amoco Egypt Gas 100 USA Exploration and production Amoco Egypt Oil 100 USA Exploration and production Africa BP Southern Africa 100 South Africa Refining and marketing Far East Indonesia Atlantic Richfield Bali North 100 Indonesia Exploration and production Singapore BP Singapore Pte* 100 Singapore Refining and marketing Australasia Australia BP Australia 100 Australia Integrated oil operations BP Developments Australia 100 Australia Exploration and production BP Finance Australia 100 Australia Finance New Zealand BP Oil New Zealand 100 New Zealand Marketing Western Hemisphere Canada Amoco Canada Petroleum Company 100 Canada Exploration and production Trinidad Amoco Energy Company of Trinidad and Tobago 90 USA Exploration and production Amoco Trinidad (LNG) B.V. 100 Netherlands Exploration and production USA Atlantic Richfield Co. 100 USA ( Exploration and production, BP America* 100 USA ( gas and power, refining BP Amoco Company 100 USA ( and marketing, pipelines Standard Oil Co. 100 USA ( and chemicals Vastar Resources Inc. 100 USA Exploration and production </TABLE> 62
ITEM 5 -- OPERATING AND FINANCIAL REVIEW AND PROSPECTS GROUP OPERATING RESULTS <TABLE> <CAPTION> Years ended December 31, -------------------------- Highlights 2000 1999 1998 ----- ----- ----- <S> <C> <C> <C> <C> Total replacement cost operating profit........... ($ million) 17,756 8,894 6,521 Replacement cost profit before exceptional items.. ($ million) 11,214 5,330 3,959 Replacement cost profit for the year.............. ($ million) 11,142 3,280 4,611 Historical cost profit for the year............... ($ million) 11,870 5,008 3,220 Profit per ordinary share (diluted)............... (cents) 54.48 25.68 16.70 Dividends per ordinary share...................... (cents) 20.5 20.0 19.8 </TABLE> During 2000 the Company acquired Atlantic Richfield Company (ARCO) and Burmah Castrol plc (Burmah Castrol) and the 18% minority interest in Vastar Resources Inc. (Vastar), a subsidiary of ARCO. We also purchased most of ExxonMobil's assets used by the fuels refining and marketing operation in Europe and made a number of minor acquisitions. All these business combinations have been accounted for using the acquisition method of accounting. BP's results in 2000 reflect the inclusion of ARCO and Burmah Castrol and the full consolidation of the European fuels joint venture from April 14, July 7, and August 1, 2000 respectively. As well as reporting net income (profit after inventory holding gains and losses, calculated on a first-in, first-out basis), and after exceptional items (as defined by UK GAAP: profits and losses on sale and termination of operations and fundamental restructuring costs), BP also reports results on a replacement cost basis (excluding inventory holding gains and losses) and before exceptional items. In addition the Group discloses the amount and nature of special items which are non-recurring charges and credits that are not classified as exceptional items under UK GAAP. This is done in order to provide a more comparable basis to the results and disclosures of US companies and to indicate underlying trading performance undistorted by significant restructuring, integration and other one-off charges and credits. Special charges have been significant in 2000 and 1999. The discussion below addresses each of these various measures and disclosures. The trading environment was strong in 2000, with high oil and gas prices and significantly improved refining margins being partly offset by pressure on marketing margins from higher product costs and the weaker chemicals environment, owing to high feedstock costs and a weak euro. In 2000, replacement cost profit before exceptional items (which excludes inventory holding gains and losses) was $11,214 million compared with $5,330 million in 1999. The result for 2000 includes a contribution from ARCO for the period from April 14,2000, a contribution from Burmah Castrol for the period from July 7, 2000 and reflects the full consolidation of the European fuels business from August 1,2000. In addition to exceptional items (as identified under UK GAAP), these results include special charges of $1,994 million ($1,454 million after tax) in 2000 and $1,210 million ($876 million after tax) in 1999, and depreciation and amortization of $1,535 million (1999 nil) arising from the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions in 2000. The special items in 2000 primarily comprise ARCO, Vastar and Burmah Castrol integration costs, rationalization costs following the BP and Amoco merger, a provision against the Group's chemicals investment in Indonesia, environmental charges and asset write-downs. The major components of the special charges in 1999 were integration costs, costs associated with the restructuring programme, write-downs in respect of asset impairments and project costs in respect of process improvement and outsourcing. The replacement cost operating profit for 2000 reflects the strong trading environment, together with the benefits of recent integration and restructuring and productivity improvements. Included in this result are estimated amounts of $569 million ($1,193 million after ajusting for special items) in respect of ARCO, $182 million in respect of the purchased interest in the European fuels joint venture, and a loss of $125 million (loss of $7 million after adjusting for special items) in respect of Burmah Castrol, representing their respective operating results since their dates of acquisition. Reductions in the combined cost structure of BP, ARCO and Burmah Castrol are proceeding according to plan, with the achievement of $2 billion year-on-year reductions in 2000. The historical cost profit for 2000 was $11,870 million including inventory holding gains of $728 million. This compares with a profit of $5,008 million in 1999 after inventory holding gains of $1,728 million. There were net exceptional gains of $220 million (loss of $72 million after tax) in 2000 compared with net exceptional losses in 1999 of $2,280 million ($2,050 million after tax). 63
<TABLE> <CAPTION> Years ended December 31, ------------------------ Special items 2000(a) 1999 1998 ----- ----- ----- ($ million) <S> <C> <C> <C> Restructuring, integration and rationalization costs BP.................................................... 624 903 97 ARCO (including Vastar)............................... 633 -- -- Burmah Castrol........................................ 151 -- -- ----- ----- ----- 1,408 903 97 Provision against fixed asset investments................ 181 -- -- Asset write-downs........................................ 61 223 475 Litigation............................................... 63 60 -- Environmental charges.................................... 170 -- -- Other.................................................... -- -- 13 ----- ----- ----- 1,883 1,186 585 Interest -- bond redemption charges...................... 111 24 12 ----- ----- ----- Total special items before tax........................... 1,994 1,210 597 ===== ===== ===== </TABLE> (a) Includes special items of $624 million and $118 million incurred directly by ARCO and Burmah Castrol respectively. The return on average capital employed (ROACE), based on replacement cost profit before exceptional items, was 16% (17% after adjusting for special items) compared with 12% (13% after adjusting for special items) in 1999. Owing to the significant acquisitions that have taken place during the year, the annual ROACE for 2000 has been calculated as the average of the four discrete quarterly ROACEs. The acquisitions of ARCO and Burmah Castrol in 2000, increased our employee numbers by approximately 25,000. Following integration and rationalization activities 4,000 employees are likely to leave the Group, of which 3,000 had left by the end of 2000. In 1999, following the merger of BP and Amoco, some 16,000 employees left the Group through severance or outsourcing arrangements, a further 3,000 employees left in 2000. Of these, some 14,000 were based in the USA. The reductions arose mainly in Houston, Texas; Chicago, Illinois; and Cleveland and Warrensville, Ohio. In 1999, replacement cost profit before exceptional items (which excludes inventory holding gains and losses) was $5,330 million compared with $3,959 million in 1998, representing an increase of 35%. In addition to exceptional items (as identified under UK GAAP), these results included net special charges of $1,210 million ($876 million after tax) in 1999 and $597 million ($469 million after tax) in 1998. The major components of the special charges in 1999 were integration costs, costs associated with the restructuring programme, write-downs in respect of asset impairments and project costs in respect of process improvement and outsourcing. The special charges in 1998 consisted principally of write-downs in respect of asset impairments. After adjusting for these special charges, the 1999 result was 40% higher than that of 1998. The return on average capital employed, based on replacement cost profit before exceptional items, was 12% (13% after adjusting for special items) representing an increase of three percentage points over 1998. The historical cost profit for 1999 was $5,008 million including inventory holding gains of $1,728 million. This compared with a profit of $3,220 million in 1998 after inventory holding losses of $1,391 million. There were net exceptional losses of $2,280 million ($2,050 million after tax) in 1999 compared with net exceptional profits in 1998 of $850 million ($652 million after tax). Owing to the significant acquisitions that took place in 2000, in addition to its reported results BP is presenting pro forma results adjusted for special items in order to enable shareholders to assess current performance in the context of our past performance and against that of our competitors. The pro forma result, adjusted for special items, has been derived from our UK GAAP accounting information but is not in itself a recognized UK or US GAAP measure. 64
<TABLE> <CAPTION> Pro forma result adjusted for Reconciliation of reported profit/loss to Acquisition Special special pro forma result adjusted for special items Reported amortization (a) items (b) items ---------- ------------ ------- --------- ($ million) <S> <C> <C> <C> <C> Year ended December 31, 2000 Exploration and Production................ 14,012 1,174 524 15,710 Gas and Power............................. 186 -- -- 186 Refining and Marketing.................... 3,908 440 595 4,943 Chemicals................................. 760 -- 276 1,036 Other businesses and corporate............ (1,110) -- 488 (622) ------ ------ ------ ------ Replacement cost operating profit......... 17,756 1,614 1,883 21,253 Interest expense.......................... (1,770) -- 111 (1,659) Taxation.................................. (4,680) -- (540) (5,220) Minority shareholders' interest........... (92) (79) -- (171) ------ ------ ------ ------ Replacement cost profit before exceptional items........................ 11,214 1,535 1,454 14,203 ------ ====== ====== ------ per ordinary share (cents)............. 51.82 65.63 ====== ====== Year ended December 31, 1999 Exploration and Production................ 6,983 -- 299 7,282 Gas and Power............................. 211 -- -- 211 Refining and Marketing.................... 1,840 -- 242 2,082 Chemicals................................. 686 -- 247 933 Other businesses and corporate............ (826) -- 398 (428) ------ ------ ------ ------ Replacement cost operating profit......... 8,894 -- 1,186 10,080 Interest expense.......................... (1,316) -- 24 (1,292) Taxation.................................. (2,110) -- (334) (2,444) Minority shareholders' interest........... (138) -- -- (138) ------ ------ ------ ------ Replacement cost profit before exceptional items........................ 5,330 -- 876 6,206 ------ ------ ====== ------ per ordinary share (cents)............ 27.48 32.00 ====== ====== Year ended December 31, 1998 Exploration and Production................ 3,173 -- 393 3,566 Gas and Power............................. 58 -- 92 150 Refining and Marketing.................... 2,564 -- -- 2,564 Chemicals................................. 1,100 -- 50 1,150 Other businesses and corporate............ (374) -- 50 (324) ------ ------ ------ ------ Replacement cost operating profit......... 6,521 -- 585 7,106 Interest expense.......................... (1,177) -- 12 (1,165) Taxation.................................. (1,322) -- (128) (1,450) Minority shareholders' interest........... (63) -- -- (63) ------ ------ ------ ------ Replacement cost profit before exceptional items........................ 3,959 -- 469 4,428 ------ ====== ====== ------ per ordinary share (cents)............ 20.62 23.06 ====== ====== </TABLE> - ---------- (a) Acquisition amortization refers to depreciation relating to the fixed asset revaluation adjustment and amortization of goodwill consequent upon the ARCO and Burmah Castrol acquisitions in 2000. There was no acquisition amortization in 1999 and 1998. (b) The special items refer to non-recurring charges and credits reported in the year. 65
<TABLE> <CAPTION> Return on average capital employed (ROACE) 1Q 2000 2Q 2000 3Q 2000 4Q 2000 ------- ------- ------- ------- ($ million) <S> <C> <C> <C> <C> Replacement cost profit before exceptional items.... 2,677 2,791 2,947 2,799 Interest and minority shareholders' interest........ 364 398 472 628 Acquisition amortization and special items (post tax) 30 861 886 1,180 ------- ------- ------- ------- 3,071 4,050 4,305 4,607 ------- ------- ------- ------- Reported average capital employed (a)............... 59,571 94,548 96,333 94,402 Acquisition adjustment (b).......................... -- (18,519) (22,172) (21,574) ------- ------- ------- ------- 59,571 76,029 74,161 72,828 ------- ------- ------- ------- ROACE -- replacement cost basis..................... 20% 13% 14% 15% ------- ------- ------- ------- ROACE -- pro forma basis (c)........................ 21% 21% 23% 25% ======= ======= ======= ======= </TABLE> - ---------- (a) Capital employed is defined as net assets plus total finance debt. (b) Acquisition adjustment refers to the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions. (c) Based on the pro forma result adjusted for special items and capital employed excluding the fixed asset revaluation adjustment and goodwill resulting from the ARCO and Burmah Castrol acquisitions. (d) The annual ROACE, based on the average of the four discrete quarterly ROACEs, is 16% on a replacement cost basis and 23% on a pro forma basis. <TABLE> <CAPTION> Year ended Capital expenditure and acquisitions (a) December 31, 2000 ----------------- ($ million) <S> <C> BP as reported.................................................... 20,107 Significant one-off cash investments: Burmah Castrol issued share capital............................ 4,779 Minority interest in Vastar.................................... 1,618 ExxonMobil share of the former BP/Mobil European joint venture. 1,479 2.2% interest in PetroChina.................................... 578 2.2% interest in Sinopec....................................... 416 Exxon's aviation lubricants business........................... 66 ----- 8,936 Continuing operations: Expenditure by acquired businesses............................. 2,234 Ongoing expenditure............................................ 8,937 ----- Continuing operations............................................. 11,171 ===== </TABLE> - ---------- (a) Excludes $27,506 million for the ARCO acquisition. Capital expenditure and acquisitions (excluding the cost of the ARCO acquisition) in 2000 amounted to $20,107 million. Excluding the cost of other significant one-off cash investments and expenditure by acquired businesses, capital expenditure was $8,937 million in 2000 compared with $6,945 million in 1999. Capital expenditure in 1999 reflected reduced investment at the time of the BP and Amoco merger. Capital expenditure in 2001 is likely to be around $12-13 billion. This is consistent with historic levels of investment for the enlarged group. By focusing on the better investment opportunities, this level of expenditure will permit growth investment in Exploration and Production to enable the business to achieve targeted production growth of at least 5.5% a year over the next five years (against an end 2000 baseline). 66
The total dividends announced for 2000 were $4,625 million, against $3,884 million in 1999. Dividends per share for 2000 were 20.50 cents, compared with 20.00 cents per share in 1999, an increase of 2.5%. The Company intends to continue to pay dividends in the future of around 50% of our replacement cost profit before exceptional items after adjusting for special items and acquisition amortization, adjusted to mid-cycle business conditions. Acquisition amortization refers to depreciation relating to the fixed asset revaluation adjustment and amortization of goodwill consequent upon the ARCO and Burmah Castrol acquisitions. Mid-cycle conditions are our best estimate of likely average prices and margins over the long term. The Company also intends to continue the operation of the Dividend Reinvestment Plan (DRIP) for shareholders who wish to receive their dividend in the form of shares rather than cash. The BP Amoco Direct Access Plan for US and Canadian investors also includes a dividend reinvestment feature. After approval at the annual general meeting in April 2000 for the Company to repurchase its own shares, a total of 222 million shares were repurchased and cancelled in 2000 at a cost of $2 billion. Further repurchases of 60 million shares at a cost of $500 million were made during the first quarter of 2001. The company will seek approval from shareholders at the April 2001 annual general meeting to continue repurchasing shares. The approval would allow shares to be bought back as and when the Group's funding position permits. Exceptional Items Following completion of the merger between BP and Amoco on December 31, 1998 and in the context of low oil prices at the time, BP undertook a strategic and portfolio review in early 1999. This review was completed in the Spring of 1999 and resulted, among other things, in the development of an asset divestment programme. The guiding principle of the strategic and portfolio review was to concentrate the combined Group's operations on areas of competitive strength and, in the upstream portfolio, to dispose of assets which would not be robustly economic on the basis of conservative assumptions about future oil and natural gas prices. In 2000, exceptional items consisting of the profit or loss on sale of fixed assets and businesses and termination of operations, were $220 million before tax and related mainly to disposal profits on the sale of the Group's common interest in Altura Energy, the sale of the Alliance refinery and the divestment of exploration and production interests in Trinidad, the UK and the USA, partially offset by the loss on sale of certain Venezuelan upstream interests and on the subvention of Singapore Aromatics Company bank loans in connection with the closure of our joint venture. The disposals in 2000 were part of the asset divestment programme. In 1999 the net exceptional losses of $2,280 million before tax comprised restructuring costs of $1,943 million and a net loss on sales of businesses and fixed assets or termination of operations of $337 million. The restructuring costs arose from restructuring activity across the Group following the merger of BP and Amoco at the end of 1998 and relate predominantly to the Group's US operations. The main areas of activity were the elimination of duplication in the former BP and Amoco operations and ongoing restructuring to adapt to the changing business environment, and some further outsourcing. The major elements of the restructuring charges comprised employee severance costs ($1,212 million) and provisions to cover future rental payments on surplus leasehold office accommodation and other property ($297 million). Also included in the restructuring charges were office closure costs, contract termination payments and asset write-offs. The cash outflow for these restructuring charges during 1999 was $976 million and in 2000 was $446 million. Sales of businesses and fixed assets in 1999 included the sale of distribution terminals and service stations in the USA mandated by the Federal Trade Commission in connection with the BP and Amoco merger. As part of the asset divestment programme, the Group disposed of its Canadian oil properties, its interest in the Pedernales oil field in Venezuela and certain chemicals operations. In 1998 sales of businesses and fixed assets generated net profits before tax of $1,048 million. The principal sales were exploration and production properties in the USA and Papua New Guinea, the refinery in Lima, Ohio, the sale and leaseback of the Amoco building in Chicago, Illinois, the retail network in the Czech Republic, the Adibis fuel additives business and a speciality chemicals distribution business. Also included was the disposal by the BP/Mobil European joint venture of its retail network in Belgium. Merger transaction costs of $198 million in respect of advisers' fees and expenses were incurred in 1998. Business Operating Results Total replacement cost operating profit, which is arrived at before inventory holding gains and losses, interest expense, taxation and minority interests, and before exceptional items, was $17,756 million in 2000, $8,894 million in 1999 and $6,521 million in 1998. The business results which follow are presented on this basis. 67
Exploration and Production <TABLE> <CAPTION> Years ended December 31, -------------------------- 2000 1999 1998 ----- ----- ----- <S> <C> <C> <C> Total replacement cost operating profit............. ($ million) 14,012 6,983 3,173 Results included: Exploration expense.............................. ($ million) 599 548 921 Key statistics: Average BP oil realizations................... ($ per barrel) 26.63 16.74 12.06 Average West Texas Intermediate oil price..... ($ per barrel) 30.38 19.33 14.38 Average Brent oil price....................... ($ per barrel) 28.44 17.94 12.73 Average BP US natural gas realizations........ ($ per thousand cubic feet) 3.72 2.06 1.82 Average Henry Hub gas price (a)............... ($ per thousand cubic feet) 3.90 2.27 2.20 Crude oil production (net of royalties) (b)......... (mb/d) 1,928 2,061 2,049 Natural gas production (net of royalties) (b)....... (mmcf/d) 7,609 6,067 5,808 Total production (net of royalties) (b)(c).......... (mboe/d) 3,240 3,107 3,050 </TABLE> - ---------- (a) Henry Hub First of Month Index. (b) Includes BP's share of associated undertakings. (c) Expressed in thousands of barrels of oil equivalent per day (mboe/d). Natural gas is converted to oil equivalent at 5.8 billion cubic feet : 1 million barrels. The replacement cost operating profit for 2000 was $14,012 million compared with $6,983 million in 1999. The result for 2000 reflects a contribution from ARCO for the period from April 14, 2000. In addition, the result is after charging special items of $524 million, and depreciation and amortization arising from the fixed asset revaluation adjustment and goodwill consequent upon the ARCO acquisition of $1,174 million. Special items in 1999 amounted to $299 million. The improved result, when compared with a year ago, reflected significantly higher oil and natural gas prices, the ARCO acquisition and operational improvements. Our average realized oil prices were $9.89 a barrel higher and North American natural gas prices (i.e. in our principal gas market) were 76% above their 1999 level. Hydocarbon production in 2000 was also at record levels, with the year up 4% on 1999. Higher underlying (excluding the net impact of acquisitions and divestments) gas production and the ARCO acquisition more than offset lower oil production caused by the disposal of our common interest in Altura Energy and other non-core properties and the effect of a reduced capital spending programme in 1999. The following table summarizes the changes in oil and gas production between 1999 and 2000. In order to present a meaningful comparison against 1999, the table adjusts the reported production in 1999 and 2000 to exclude the production from significant acquisitions and divestments. A separate reconciliation for ARCO is also provided. 68
<TABLE> <CAPTION> Crude Oil and natural gas production movements Oil Gas Gas Total ------ ------ ------ ------ (mb/d) (mmcf/d) (mboe/d) (mboe/d) <S> <C> <C> <C> <C> BP 1999 as reported (A)................................. 2,061 6,067 1,046 3,107 Net acquisitions and divestments (B) UK Scott/Telford, other.................... (14) (11) (2) (16) Rest of Europe ........................................ -- -- -- -- USA Crescendo, Altura, Prudhoe Bay Unit realignment, Western gas............... (211) (93) (16) (227) Rest of World Venezuela, others....................... (54) (41) (7) (61) ------ ------ ------ ------ (279) (145) (25) (304) ------ ------ ------ ------ BP 1999 adjusted for divestments and acquisitions (C) [C=A-B]........................... 1,782 5,922 1,021 2,803 ====== ====== ====== ====== BP 2000 as reported (D)................................. 1,928 7,609 1,312 3,240 Net acquisitions and divestments (E) ARCO contribution April 14 to December 31, 2000......... (182) (1,578) (272) (454) Altura, others.......................................... (43) (35) (6) (49) ------ ------ ------ ------ (225) (1,613) (278) (503) ------ ------ ------ ------ BP 2000 adjusted for divestments and acquisitions (F) [F=D-E].......................... 1,703 5,996 1,034 2,737 ====== ====== ====== ====== Variance 2000 vs 1999 (F-C)............................ (79) 74 13 (66) ====== ====== ====== ====== %Increase (decrease)................................... (4)% 1% (2)% </TABLE> <TABLE> <CAPTION> ARCO Reconciliation Oil Gas Gas Total ------ ------ ------ ------ (mb/d) (mmcf/d) (mboe/d) (mboe/d) <S> <C> <C> <C> <C> ARCO 1999 as reported (A).............................. 623 2,378 410 1,033 Less:divestments (B) UK North Sea 4th Round.................... (18) -- -- (18) Rest of Europe ....................................... -- -- -- -- USA Alaska, Long Beach..................... (350) (35) (6) (356) Rest of World Tunisia, Ecuador, Algeria.............. (19) -- -- (19) ------ ------ ------ ------ (387) (35) (6) (393) ------ ------ ------ ------ ARCO 1999 adjusted for divestments (C) [C=A-B]......... 236 2,343 404 640 ====== ====== ====== ====== ARCO 2000 adjusted for divestments (D)................. 242 2,285 394 636 ====== ====== ====== ====== Variance 2000 vs 1999 (D-C)............................ 6 (58) (10) (4) ====== ====== ====== ====== %Increase (decrease)................................... 3% (2)% -- </TABLE> In 2000, finding and development costs averaged $3.29 a barrel of oil equivalent, against our ceiling of $3.50 per barrel. Unit lifting costs were reduced by 5% compared with 1999 to $2.50 per barrel of oil equivalent. In 2000, reserve replacement exceeded production for the seventh consecutive year, with 1.8 billion barrels of oil equivalent added to proved reserves through revisions, extensions, discoveries and improved recovery. This represents a reserve replacement ratio of 163%. During the year there were several developments in support of future hydrocarbon volume growth. In the North Sea we announced a $500-million enhanced oil recovery project at Magnus. In the deepwater Gulf of Mexico, the developments of King, King's Peak, Nakika and Horn Mountain were approved and industrial capacity of around $3 billion was secured for fabrication and installation of additional developments. In Vietnam, key elements of the $1.3-billion gas project were signed. In Alaska, a joint feasibility study for a pipeline to transport gas to the rest of the USA and Canada was agreed. 69
We recorded significant exploration success in 2000. Progress in the Gulf of Mexico deepwater continued with the discovery of Crazy Horse North which, with the adjacent Crazy Horse, discovered in 1999, has increased estimated recoverable resources in this complex. In Angola we made seven offshore discoveries, including two in the BP - operated Block 18, bringing the total of successes to 23 out of 26 wells drilled since 1996. We made two large gas finds offshore Trinidad, one of them the largest-ever in the Caribbean region. Advances in technology sharpened our performance. We applied new fibre-optic sensors in many wells to monitor pumps, pressures and flow rates, thus reducing operating costs and boosting production capacities. We added capability to our seismic imaging tools, allowing us to discern the shape of hydrocarbon reservoirs more clearly, and worked with suppliers to develop a high-strength steel to reduce the cost of gas pipelines. Our strategic plans to upgrade the portfolio continued with the acquisition of the minority interest in Vastar and the sale of BP's common interest in Altura Energy. We also agreed with partners to realign our oil and gas interests in Prudhoe Bay, allowing us to optimize operations and strengthen our gas position significantly. Capital expenditure and acquisitions rose substantially to $6,383 million in 2000 from $4,194 million in 1999. This was largely attributable to increases in development drilling in the North American gas business, the Northstar project in Alaska, Egypt gas development and projects in the Gulf of Mexico deepwater. During 2001 many new projects are expected to come on stream, including six major oil and natural gas fields in the Gulf of Mexico, Alaska, Angola, Egypt and Norway. In 1999, replacement cost operating profit was $6,983 million, an improvement of 120% over the equivalent result of 1998. The result is after charging special items of $299 million in 1999. Special items in 1998 amounted to $393 million. Our oil realizations were $4.68 a barrel higher and North American natural gas prices were 13% above their 1998 level. These environmental benefits were significantly complemented by cost savings. Oil production increased slightly compared with 1998, with rising output in the Eastern Trough Area Project (ETAP) in the North Sea and at Schiehallion and Foinaven, west of Shetland, more than offsetting declines in Alaska and in the more mature North Sea fields, and the effect of the sale of our Canadian oil interests. Natural gas production increased 4.5% to just over 6 bcf/d following the start-up of a $1-billion liquefied natural gas plant in Trinidad. Technological innovation underpinned our most significant exploration achievement in 1999 - the discovery of the largest deepwater field so far found in the Gulf of Mexico, the Crazy Horse field, in which the Group holds a 75% interest. Finding this field involved drilling through 1,800 metres (6,000 feet) of water and more than 600 metres (2,000 feet) of salt to a record depth of 7,830 metres (25,770 feet). Crazy Horse was only one of a number of major finds in 1999. In the Gulf of Mexico we announced the discovery of three other fields - Holstein, Atlantis and Mad Dog. In Angola our exploration success continued with eight new discoveries. Elsewhere there were large natural gas finds in Azerbaijan's offshore waters and in Australia's North West Shelf. In December 1999, a consortium, in which BP has a 35% interest, announced that it had been awarded a deep water concession offshore Brazil, the BFZ-2 block. Gas and Power <TABLE> <CAPTION> Years ended December 31, -------------------------- 2000 1999 1998 ---- ----- ----- <S> <C> <C> <C> <C> Total replacement cost operating profit........... ($ million) 186 211 58 Total gas sales volumes (a)....................... (mmcf/d) 14,471 8,930 8,519 </TABLE> - ---------- (a) Includes marketing, trading and supply sales. 70
The Gas and Power business, which is reported separately from January 1, 2000, is responsible for BP's world-wide gas marketing activities (although some long term gas sales contracts are also included within the Exploration and Production business) and all business development opportunities in natural gas, including gas-fired power generation. The Gas and Power stream has responsibility for the shareholding in Ruhrgas, BP's existing gas marketing and trading operations in the UK and North America, and world-wide power development activities. Gas and Power has established business development operations in Latin America, the Mediterranean, the Caspian region, the Middle East, Northern Europe, China and the Asia-Pacific region. The replacement cost operating profit for 2000 was $186 million compared with $211 million in 1999. The result for 2000 includes a contribution from ARCO for the period from April 14, 2000. The improved income from operations partly offset increased business development costs. Increased gas sales in North America, the UK and Spain contributed to total sales of 14.5 billion cubic feet per day. The following table summarizes the changes in gas sales volumes between 1999 and 2000. In order to present a meaningful comparison against 1999, the table adjusts the reported amounts in 1999 and 2000 to exclude the contribution from significant acquisitions. <TABLE> <CAPTION> Year Gas sales volumes movements ----------- (mmcf/d) <S> <C> BP 1999 as reported (A).................................................. 8,930 ====== BP 2000 as reported (B).................................................. 14,471 Less acquisitions (C) ARCO.................................................................... (2,194) Progas.................................................................. (1,236) ------ (3,430) ------ BP 2000 adjusted for acquisitions (D) [D=B-C]........................... 11,041 ====== Variance 2000 vs 1999 (D-A)............................................. 2,111 ====== %Increase .............................................................. 24% </TABLE> We became the first non-Spanish company to win customers in Spain's newly deregulated gas market. Work began on the liquefied natural gas (LNG) regasification terminal and gas-fired power station at Bilbao, Spain, and we agreed a 20-year $2.5-billion sale of LNG to power plants in the Dominican Republic. In North America acquisitions improved our wholesale and marketing capabilities. We invested in GreenMountain.com, the leading US consumer marketer of green energy and reached agreement with PetroChina to establish a gas marketing joint venture in eastern China. We became the first oil and gas company to order new-build LNG vessels not tied to a single gas source or customer. Capital expenditure and acquisitions was $279 million compared with $18 million in 1999. Expenditure in 2000 included $125 million for the first two instalments on two LNG ships and investment in GreenMountain.com. The replacement cost operating profit for 1999 was $211 million compared with $58 million in 1998. The result for 1998 is after charging special items of $92 million. Apart from the impact of special charges, the increase of $61 million in 1999 represents an increase in income from operations. Gas sales increased from 8.5 billion cubic feet per day in 1998 to 8.9 billion cubic feet per day in 1999, driven mainly by growth in North America. During 1999, we acquired all of the shares we did not own in Canada's second largest natural gas supply aggregator, ProGas. ProGas is based in Calgary, Alberta, and purchases gas from approximately 170 producers in the western Canadian Sedimentary Basin. It markets 1.45 bcf/d of gas across North America. 71
Refining and Marketing <TABLE> <CAPTION> Years ended December 31, ----------------------- 2000(a) 1999(a) 1998(a) ----- ----- ----- <S> <C> <C> <C> <C> Total replacement cost operating profit...($ million) 3,908 1,840 2,564 Global Indicator Refining Margin (b)...... ($/bbl) 4.22 1.24 2.1 Refinery throughputs...................... (mb/d) 2,916 2,522 2,698 Total marketing sales .................... (mb/d) 3,756 3,186 3,137 </TABLE> - ---------- (a) Includes BP's share of the BP/Mobil European joint venture until August 1, 2000. (b) The Global Indicator Refining Margin (GIM) is the average of seven regional indicator margins weighted for BP's crude refining capacity in each region. Each regional indicator margin is based on a single representative crude with product yields charateristic of the typical level of upgrading capacity. Refining and Marketing had an outstanding year in 2000, with record results and a highly competitive return on fixed assets. The replacement cost operating profit for 2000 was $3,908 million compared with $1,840 million in 1999. The result for 2000 includes a contribution from ARCO for the period from April 14, 2000, a contribution from Burmah Castrol for the period from July 7, 2000 and reflects the full consolidation of the BP/Mobil European fuels business from August 1, 2000. In addition, the result is after charging special items of $595 million and depreciation and amortization arising from the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions of $440 million. Special items in 1999 amounted to $242 million. The 2000 result benefited from cost reductions and a strong oil trading performance. In 2000, refining margins were stronger in all regions than in 1999, and NGL margins were generally strong. Marketing margins came under pressure due to the inability to pass through high product prices in competitive markets. The acquisition of ARCO gave us coast-to-coast market access in the USA and the acquisition of Burmah Castrol significantly increased our lubricants activities throughout the world. Since unveiling our new global brand, sites in the USA and Europe are preparing for conversion during 2001. In emerging markets, fuel sales rose by 22% and we opened 75 new retail sites in Latin America, Poland, Russia and Africa. Growth in aviation fuel sales was strong. In August 2000, we completed the purchase of ExxonMobil's 30% interest in the BP/Mobil European fuels business for $1.5 billion. The following table summarizes changes in refinery throughputs and marketing sales volumes between 1999 and 2000. In order to present a meaningful comparison against 1999, the table adjusts the reported amounts in 1999 and 2000 to exclude the contribution from significant acquisitions and divestments. <TABLE> <CAPTION> Refining Marketing Refining and Marketing volume movements throughputs sales ----------- ----------- (mb/d) (mb/d) <S> <C> <C> BP 1999 as reported (A)............................ 2,522 3,186 Alliance divestment (B)............................ (250) -- ------ ------ BP 1999 adjusted for divestments (C) [C=A-B] 2,272 3,186 ====== ====== BP 2000 as reported (D)............................ 2,916 3,756 Net acquisitions and divestments (E) ARCO............................................... (334) (352) ExxonMobil share of the former BP/Mobil European fuels JV................................ (113) (133) Burmah Castrol..................................... -- (16) Alliance........................................... (228) -- ------ ------ (675) (501) ------ ------ BP 2000 adjusted for acquisitions (F) [F=D-E] 2,241 3,255 ====== ====== Variance 2000 vs 1999 (F-C) (31) 69 ====== ====== %Increase (decrease) (1)% 2% </TABLE> 72
During 2000 we commercialized a novel process to remove sulphur from gasoline and diesel at low cost and with no loss of octane. This is helping to advance the rate at which we introduce new clean fuels. By the end of 2000, cleaner fuels had gone on sale in 56 cities worldwide, against a target of 40. Capital expenditure and acquisitions in 2000 was $8,750 million compared with $1,634 million in 1999. The Group's capital expenditure on refinery assets, including environmental expenditures and investments in line with regulatory requirements to improve product quality, totalled $1,642 million in 2000 compared with $607 million in 1999. During 2000 our Bulwer Island refinery in Queensland, Australia, commissioned a new hydrocracker complex three months ahead of schedule. We completed a project at Sines, Portugal, to develop a liquefied petroleum gas storage cavern, and progressed a similar project at Ningbo on the Chinese coast. These are examples of a number of initiatives undertaken as part of our drive for cleaner fuels. Capital expenditure on marketing assets amounted to $7,108 million in 2000 compared with $1,027 million in the previous year. The substantial increase in 2000 reflects the acquisition of Burmah Castrol and ExxonMobil's share of the BP/Mobil European joint venture. In 2000, as part of the Company's global refining strategy we completed the sale to Tosco Corporation of the Alliance refinery in Louisana and announced the intended disposal of three US refineries and their associated facilities. The three refineries -- Salt Lake City in Utah, Mandan in North Dakota and Yorktown in Virginia -- have a combined capacity of 177,000 barrels a day. In addition to the US refineries we have announced the intention to sell our 30% interest in our Singapore refinery of which BP's share is 78,000 barrels a day. The refineries will continue to operate normally during the sales process. It is anticipated that the sales process will be completed by mid-2001. During 2001, we plan to open more than 300 BP Connect convenience retail sites worldwide sporting the new helios brand mark as part of a longer-term reimaging plan. The cost of rebranding existing sites in 2001 is expected to be around $190 million. In total, we plan to have the new helios brand mark in place on more than 5,000 sites by the end of 2001. In 1999, Refining and Marketing achieved a highly competitive return on fixed assets despite plummeting margins in refining, which fell by 48% compared with the previous year. Replacement cost operating profit of $1,840 million represented a decrease of 28% compared with 1998. The result is after charging special items of $242 million in 1999. There were no special charges in 1998. Apart from the impact of special charges the decrease reflects the rise in the price of crude oil and refined products and consequent tightening of margins. The deterioration in the refining environment led to run cuts at a number of refineries. The pressure on marketing margins reflected rising product prices which could not be fully recovered in the market. Significant cost reductions moderated the effect of the harsher trading environment. In 1999 retail volumes rose while shop revenues grew faster than the market at 6%, reflecting the strength of our convenience retail business in the USA and UK. More than 170 new retail sites were opened worldwide during the year, with 90 opened in Poland, China, Venezuela and Russia. Growth in our aviation business was strong, and Air BP was recognized as the World's Best Jet Fuel Marketer by an authoritative industry survey. Chemicals <TABLE> <CAPTION> Years ended December 31, -------------------------- 2000 1999 1998 ----- ----- ----- <S> <C> <C> <C> <C> Total replacement cost operating profit.......... ($ million) 760 686 1,100 Chemicals Indicator Margin (a)................... ($/te) 121(b) 114 139 Production volumes (c)........................... (kte) 22,065 21,853 20,570 </TABLE> - ---------- (a) The Chemicals Indicator Margin (CIM) is a weighted average of externally-based product margins. It is based on market data collected by Chem Systems in their quarterly market analyses, then weighted based on BP's product portfolio. While it does not cover our entire portfolio, it includes a broader range of products than our previous indicator. Among the products and businesses covered in the CIM are the olefins and derivatives, the aromatics and derivatives, linear alpha olefins, acetic acid, vinyl acetate monomer and nitriles. Not included are Fabrics and Fibres, plastic fabrications, poly alpha olefins, anhydrides, Engineering Polymers and Carbon Fibres, speciality intermediates, and the remaining parts of the solvents and acetyls businesses. (b) Provisional. The data for the current year is based on eleven months of actual data and one month of provisional data. (c) Includes BP share of associated undertakings and other interests in production. 73
Chemicals' replacement cost operating profit was $760 million compared with $686 million in 1999. The results for 2000 and 1999 include special charges of $276 million and $247 million respectively. Productivity improvements in 2000 more than offset the effects of the weaker environment. Chemicals' demand was firm in the first half of 2000, but then weakened in the final two quarters as the global economy slowed. Annual production rose 1% to 22.1 million tonnes, despite operational difficulties at Grangemouth, Scotland. Several initiatives to promote cost and capital efficiency helped offset pressure on margins that were close to cyclical lows, as high oil and gas prices boosted feedstock costs. The weakness of the euro added pressure on margins in our European operations. Capital expenditure and acquisitions in 2000 was $1,585 million compared with $1,215 million in 1998. A major programme of UK investment continued with the successful commissioning of polypropylene and polyethylene units at Grangemouth. In 2000 our chemicals activities focused on areas of competitive advantage. We reached agreement in principle to acquire Bayer's 50% shareholding in the Erdolchemie joint venture in Germany; this represents the 50% of the joint venture we do not already own. Our polypropylene joint venture with ATOFINA was dissolved, giving us full control of assets at Grangemouth and a 50% share of production in Lavera, France. We commissioned a world-scale acetic acid plant in Malaysia and made progress on planning a $2.5-billion ethylene and derivatives joint venture near Shanghai in China. In November construction began of a $360-million PTA plant at Zhuhai in southern China, and another PTA plant was announced in Taiwan. We announced several related deals with Solvay of Belgium, involving assets with a combined turnover of $2.6 billion. During 2001, petrochemicals capacity is planned to be increased at Grangemouth and Hull in the UK, and in Canada, production of linear alpha-olefins is scheduled to begin at a new world-scale facility. In 1999, replacement cost operating profit was $686 million compared with $1,110 million in 1998. The result is after charging special items of $247 million in 1999. Special charges in 1998 were $50 million. Chemicals margins in several commodity product areas fell to levels below the low points seen in previous cycles. At the same time the effects of the financial crisis in Asia continued to be felt, especially in Europe, where weakness of the euro also contributed to pressure on margins. This adverse external environment was offset partially by a clear focus on cost reductions and releasing the value of the merger of BP and Amoco. Total volume of product manufactured rose by 6% to an all-time record of 21.9 million tonnes as new capacity came on stream and production reliability increased. These increases in production were partly offset by disposals. In 1999 we disposed of the Verdugt acid salts business in Europe, the Plaskon electronic materials business based in the USA and Singapore, our share of the olefins cracker in Wilton, UK, the US Fibers and Yarns business and the Plaspack Kunststoffe plastic net and webbing business and we completed the sale and leaseback of railcars in the USA. In addition, we announced the closure of our joint-venture Singapore Aromatics complex. In 2000, BP refinanced this entity's bank loans and sold its interest in this entity to ExxonMobil, resulting in a loss of $209 million ($148 million after tax). In 1999, a number of new chemicals projects aimed at strengthening our portfolio were sanctioned or announced, including a new 250,000 tonnes a year linear alpha-olefins plant in Alberta, Canada, and the expansion of trimellitic anhydride capacity at our plant in Joliet, Illinois. In China our 150,000-tonnes-a-year acetic acid joint venture with Sinopec at Yaraco was commissioned early in the year. Another joint venture with Sinopec - - the detailed planning phase of a world-scale 900,000-tonnes-a-year ethylene cracker and derivative product units near Shanghai - received official approval in the Autumn. Start-up is expected in 2005. Other Businesses and Corporate <TABLE> <CAPTION> Years ended December 31, -------------------------- 2000 1999 1998 ----- ----- ----- <S> <C> <C> <C> <C> Replacement cost operating loss........ ($ million) (1,110) (826) (374) </TABLE> Other Businesses and Corporate comprises Finance, BP Solar, our coal and aluminium assets, our investments in PetroChina and Sinopec, interest income and costs relating to corporate activities worldwide. The net cost of Other Businesses and Corporate in 2000 amounted to $1,110 million. This includes a contribution from ARCO for the period from April 14, 2000 and special charges of $488 million. BP Solar production and shipments for 2000 were 31% higher than in 1999. A total of 42 megawatts (MW) of solar panel generating capacity was sold in 2000 (1999, 32 MW and 1998, 27 MW). 74
During 2000, we purchased a 2.2% interest in PetroChina for $578 million and a 2.2% interest in Sinopec for $416 million - two of Asia's largest oil and natural gas companies. The net cost of Other Businesses and Corporate of $826 million for 1999 included $398 million for rationalization costs following the BP and Amoco merger. Interest Expense Interest expense in 2000 was $1,770 million compared with $1,316 million in 1999. These amounts included special charges of $111 million and $24 million respectively, arising from the early redemption of bonds. After adjusting for these special charges, the increase in Group interest expense in 2000 reflected higher debt and interest rates. Interest expense in 1999 was $1,316 million compared with $1,177 million in 1998. The increase reflected lower capitalized interest and higher average debt, the effects of which were partly offset by lower interest rates. Taxation The charge for corporate taxes in 2000 was $4,972 million compared with $1,880 million in 1999, and $1,520 million in 1998. The effective tax rate on historical cost profit was 29% in 2000, 27% in 1999 and 32% in 1998. The higher rate in 2000 compared to 1999 reflects the non-deductibility for tax purposes of ARCO and Burmah Castrol acquisition amortization; the reduced impact of beneficial timing differences due to the higher level of income; and reduced untaxed inventory holding gains, partly mitigated by the utilization of significant brought-forward tax credit balances. The lower rate in 1999 compared with 1998 was due to the impact of unrelieved inventory holding losses in 1998, partly offset by the low tax relief on net exceptional losses in 1999. The effective tax rate on replacement cost profit before exceptional items was 29% (27% after adjusting for special items and acquisition amortization), compared with 28% in 1999 and 25% in 1998. The higher rate in 2000 was caused by the non-deductability for tax purposes of the acquisition amortization and the reduced impact of beneficial timing differences due to the higher level of income. The increase in effective rate in 1999 over 1998 reflected the effects of tax on inventory holding gains in 1999 and inventory holding losses in 1998. Outlook The overall trading environment is expected to remain generally positive, notwithstanding less favourable economic conditions than those experienced in 2000. Oil and gas prices are likely to remain volatile, in a trading range below the peaks seen during 2000. Refining margins should continue to be supported by tightness in product stocks, though in the first quarter the effect of strengthened margins in the USA were more than offset by weaker margins in Europe and Asia. Marketing margins are likely to reflect competitive pressures after recent falls in the oil price. The chemicals trading environment is likely to come under further pressure from a moderation in economic growth and increasing supply capacity. Environmental Expenditure <TABLE> <CAPTION> Years ended December 31, -------------------------- 2000 1999 1998 ----- ----- ----- ($ million) <S> <C> <C> <C> Operating expenditure....................................... 653 414 446 Capital expenditure......................................... 298 246 426 Clean-ups................................................... 81 92 129 New provisions for environmental remediation................ 228 145 13 New provisions for decommissioning.......................... 139 80 130 </TABLE> Operating and capital expenditure on the prevention, control, abatement or elimination of air, water and solid waste pollution is often not incurred as a discrete identifiable transaction. Instead, it forms part of a larger transaction which includes, for example, normal maintenance expenditure. The figures for environmental operating and capital expenditure in the table are therefore estimates, based on the definitions and guidelines of the American Petroleum Institute. 75
Environmental operating and capital expenditures were higher in 2000 principally due to the inclusion of ARCO and Burmah Castrol. Similar levels of operating and capital expenditure are expected in the foreseeable future. In addition to operating and capital expenditures, we also create provisions for future environmental remediation. Expenditure against such provisions is normally incurred in subsequent periods and is not included in environmental operating expenditure reported for such periods. Included within special items is a charge of $170 million relating to environmental liabilities at certain US sites. The charge appears within operating expenditure ($50 million) and in new provisions for environmental remediation ($120 million). Provisions for environmental remediation are made when a clean-up is probable and the amount reasonably determinable. Generally, their timing coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The extent and cost of future remediation programmes are inherently difficult to estimate. They depend on the scale of any possible contamination, the timing and extent of corrective actions, and also the Group's share of the liability. Although the cost of any future remediation could be significant, and may be material to the result of operations in the period in which it is recognized, we do not expect that such costs will have a material effect on the Group's financial position or liquidity. We believe our provisions are sufficient for known requirements; and we do not believe that our costs will differ significantly from those of other companies (with similar assets) engaged in similar industries or that our competitive position will be adversely affected as a result. In addition, we make provisions over the useful lives of our oil- and gas-producing assets and related pipelines to meet the cost of eventual decommissioning. Provisions for environmental remediation and decommissioning are usually set up on a discounted basis, as required by Financial Reporting Standard No.12, `Provisions, Contingent Liabilities and Contingent Assets'. Further details of decommissioning and environmental provisions appear in Item 18 -- Note 27 of Notes to Financial Statements. See also Item 4 -- Information on the Company -- Environmental Protection. Insurance The Group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the Group. Losses will therefore be borne as they arise rather than being spread over time through insurance premia with attendant transaction costs. The position will be reviewed periodically. The Euro As a result of the Treaty establishing the European Community, as amended by the Treaty on European Union, (the Treaty), European economic and monetary union (EMU) has occurred for eleven out of the fifteen member countries of the European Union (participating countries). The final stage of the Treaty began on January 1, 1999. For the participating countries, the fixed conversion rates between their sovereign currencies (legacy currencies) prior to January 1, 1999 and the euro have been established. The euro has been adopted as their common legal currency. The legacy currencies are scheduled to remain legal tender as denominations of the euro between January 1, 1999 and January 1, 2002 (the transition period). The United Kingdom has not participated initially in EMU, but may do so at a later time. The current policy of the UK government is that any decision to join EMU will only be taken after a national referendum of the people and, in any event, not before 2002. BP's commercial and financial processes were successfully adapted to allow its European operations to undertake transactions in the euro and capture competitive advantage offered by the new currency, from January 1, 1999. In common with experience generally across Europe, the actual level of transactions in euros for our businesses continues to be low. The currency of accounting records and the related systems are now being converted to euros. The capability to conduct business in the former national currencies will be retained as long as necessary. The costs associated with the euro programme are estimated at $100 million, of which some $60 million had been incurred and expensed by the end of 2000. It is difficult to predict whether the euro will affect the level or volatility of foreign exchange rates. However, we do not expect that the introduction of the euro will have a significant effect on the Group's results of operations, its financial position or liquidity. 76
LIQUIDITY AND CAPITAL RESOURCES Cash Flow <TABLE> <CAPTION> Years ended December 31, -------------------------- 2000 1999 1998 ----- ----- ----- ($ million) <S> <C> <C> <C> Net cash inflow from operating activities................... 20,416 10,290 9,586 Net cash inflow (outflow) .................................. 3,743 (82) (906) </TABLE> Net cash inflow for the year was $3,743 million, compared with an outflow of $82 million in 1999. This results from an almost doubling of operating cash flow partially offset by higher tax payments and net cash outflows from capital expenditure, acquisitions and disposals. Net cash inflow from operating activities increased to $20,416 million in 2000 from $10,290 million in 1999. The main factor in this improvement was the increased operating earnings. Dividends from joint ventures and associated undertakings decreased from $1,168 million in 1999 to $1,039 million in 2000. The principal factor in this decrease was the dissolution in August, 2000 of the BP/Mobil European joint venture partially offset by an increase in dividends from other associated undertakings. The net cash outflow from servicing of finance and returns from investments decreased to $892 million from $1,003 million in 1999, principally because of the lower payment of dividends to minority shareholders. The increase in interest payments was largely offset by the increase in interest receipts. Tax payments rose to $6,198 million in 2000 from $1,260 million in 1999 reflecting increased taxation as a result of higher profits and approximately $1.6 billion relating to the FTC mandated disposal of ARCO's Alaskan businesses and certain pipeline interests in the Lower 48 States, which are accounted for under the allocation of purchase price as opposed to the current tax charge. Payments for capital expenditures on fixed assets net of proceeds from sales of fixed assets, amounted to $7,072 million, an increase of $1,687 million on 1999. Higher capital expenditure in 2000 was partly offset by higher disposal proceeds. We are targeting annual investment in the $12-13 billion range over the period 2001-2003 which is consistent with historic levels of investment for the enlarged group. Acquisitions and disposals of businesses produced a net cash inflow of $865 million compared with $243 million in 1999. The increase in disposal proceeds of $7,041 million, which included $6,803 million for the FTC mandated sales, was largely offset by increased spend on acquisitions and investments in associated undertakings. Overall net cash outflow for capital expenditure and acquisitions, net of disposals, was $6,207 million (1999 $5,142 million). Dividend payments increased to $4,415 million from $4,135 million in 1999 reflecting the increase in shares in issue as a result of the ARCO acquisition and the dividend increase in the third quarter of 2000, partially offset by share repurchases during the year. Net cash outflow for 1999 was $82 million compared with $906 million in 1998. The change reflected improved operating results and lower net capital expenditure, partly offset by restructuring and integration costs and higher dividend payments. Net cash inflow from operating activities increased to $10,290 million in 1999 from $9,568 million in 1998. The main factors in this improvement were increased operating earnings offset to a large extent by an increase in the funding requirement for working capital caused by the increase in oil prices. Dividends from joint ventures and associated undertakings increased from $966 million in 1998 to $1,168 million in 1999. The principal factor in this increase was improved results from the BP/Mobil joint venture partially offset by a decrease in dividends from other associated undertakings. The net cash outflow from servicing of finance and returns from investments increased to $1,003 million from $825 million in 1998, principally as a result of higher interest payments being made on the higher average level of debt. Tax payments fell from $1,705 million in 1998 to $1,260 million in 1999 reflecting a degree of lag in the timing of tax payments. Payments for capital expenditures on fixed assets net of proceeds from sales of fixed assets in 1999, amounted to $5,385 million, a reduction of $1,913 million on 1998. This reduction was a result of the Group's decision to increase the focus of its capital programme. 77
Acquisitions and disposals of businesses produced a net cash inflow of $243 million compared with $778 million in 1999. The major element of this reduction in cash inflow was the turnaround of the funding of joint ventures from a net release of funds in 1998 of $708 million to a net requirement of $750 million in 1999. This increase in cash outflow was partially offset by an increase in proceeds from the sale of businesses which amounted to $1,292 million in 1999 compared with $780 million in 1998. Also within this net reduction were cash outflows for acquisitions and investments in associated undertakings which amounted to $299 million, a decrease of $411 million over 1998. Dividend payments increased by $1,727 million to $4,135 million in 1999. This reflected the termination of the former BP share dividend plan and the fifth dividend payment in 1999 due to the harmonization and acceleration of the payment timetable. Financing the Group's Activities The Group's principal commodity, oil, is priced internationally in dollars. Group policy has been to minimize economic exposure to currency movements by financing operations with US dollar debt wherever possible, otherwise by using currency swaps when funds have been raised in currencies other than dollars. The Group's finance debt is almost entirely in US dollars. Net debt, that is debt less cash and liquid resources, was $19,359 million at the end of 2000, an increase of $6,336 million over the year. Gross debt consisted of long term borrowings of $14,772 million and short term borrowings of $6,418 million. Net debt of $6,579 million was acquired with ARCO and Burmah Castrol. Following the acquisitions, the Group repurchased $960 million of outstanding debt in order to provide greater financing flexibility for the future. The ratio of net debt to net debt plus equity was 21%, compared with 23% a year ago. After adjusting for the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions, the ratio of net debt to net debt plus equity was 27%. We expect to keep this adjusted ratio in the range of 20-30%. The maturity profile and fixed/floating rate characteristics of the Group debt are described in Item 18 -- Financial Statements -- Note 25. At December 31, 2000 contracts had been placed for authorized future capital expenditure estimated at $4,141 million, mainly in respect of exploration and production activities. Such expenditure is expected to be financed largely by cash flow from operating activities. At December 31, 2000, the Group had available undrawn committed borrowing facilities of $3,450 million ($3,000 million at December 31, 1999). BP has in place a Debt Issuance Programme (the Programme). Under the Programme certain subsidiaries of the Group may from time to time issue debt securities guaranteed by the Company. The debt may have a minimum maturity of one month and no maximum maturity. Aggregate debt outstanding under the Programme will not at any time exceed $6 billion or the equivalent in other currencies. At March 30, 2001, the amount drawn down against this Programme was $2,237 million. BP believes that, taking into account unutilized market facilities, the Group has sufficient working capital for foreseeable requirements. Liquidity Risk Liquidity risk is the risk that suitable sources of funding for the Group's business activities may not be available. The Group has long-term debt ratings of Aa1 and AA+ assigned respectively by Moody's and Standard and Poor's. The Group has access to a wide range of funding at competitive rates through the capital markets and banks. It co-ordinates relationships with banks, borrowing requirements, foreign exchange requirements and cash management centrally. The Group believes it has access to sufficient funding and has also undrawn committed borrowing facilities to meet currently foreseeable borrowing requirements. At December 31, 2000, the Group had available undrawn committed facilities of $3,450 million. These committed facilities, which are mainly with a number of international banks, expire in 2001. The Group expects to renew the facilities on an annual basis. Credit Risk Credit risk is the potential exposure of the Group to loss in the event of non-performance by a counterparty. The credit risk arising from the Group's normal commercial operations is controlled by individual operating units within guidelines. In addition, as a result of its use of financial and commodity instruments, including derivatives, to manage market risk, the Group has credit exposures through its dealings in the financial and specialized oil and gas markets. The Group controls the related credit risk by entering into contracts only with highly credit-rated counterparties and through credit approvals, limits and monitoring procedures, and does not usually require collateral or other security. Counterparty credit validation, independent of the dealers, is undertaken before contractual commitment. The Group has not experienced material non-performance by any counterparty. 78
ITEM 6 -- DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES DIRECTORS AND SENIOR MANAGEMENT The following lists the 21 directors on the board and the company secretary. <TABLE> <CAPTION> Initially elected Name or appointed - ------ -------------- <S> <C> <C> P D Sutherland................ Non-executive co-chairman (a) Chairman since May 1997 Director since July 1995 Sir Ian Prosser............... Non-executive deputy chairman (a)(b)(c) Deputy chairman since February 1999 Director since May 1997 Sir John Browne............... Executive director (Group chief executive) September 1991 Dr J G S Buchanan............. Executive director October 1996 R F Chase..................... Executive director (Deputy group chief March 1992 executive) W D Ford...................... Executive director January 2000 Dr C S Gibson-Smith........... Executive director September 1997 Dr B E Grote.................. Executive director August 2000 R L Olver..................... Executive director January 1998 R S Block..................... Non-executive director (a)(d) December 1998 J H Bryan..................... Non-executive director (a)(c) December 1998 E B Davis, Jr................. Non-executive director (a)(b)(c) December 1998 R J Ferris.................... Non-executive director (a)(b) December 1998 C F Knight.................... Non-executive director (a)(b) October 1987 F A Maljers................... Non-executive director (a)(d) December 1998 Dr W E Massey................. Non-executive director (a)(d) December 1998 H M P Miles................... Non-executive director (a)(c)(d) June 1994 Sir Robin Nicholson........... Non-executive director (a)(b) October 1987 M H Wilson.................... Non-executive director (a)(c) December 1998 Sir Robert Wilson............. Non-executive director (a)(c)(d) July 1998 The Lord Wright of Richmond... Non-executive director (a)(b) October 1991 J C Hanratty.................. Secretary October 1994 </TABLE> - ---------- (a) Member of the Chairman's Committee. (b) Member of the Remuneration Committee. (c) Member of the Audit Committee. (d) Member of the Ethics and Environment Assurance Committee. Mr H L Fuller retired as executive co-chairman and director of the board on March 31, 2000. Mr B K Sanderson retired as an executive director on September 30, 2000. Dr B E Grote was appointed an executive director with effect from August 3, 2000. Mrs R S Block will retire as a non-executive director on April 19, 2001, Dr C S Gibson-Smith will retire as an executive director on April 19, 2001 and the Lord Wright of Richmond will retire as a non-executive director on April 30, 2001. BP's articles of association require directors who have held office for three years or more since they were appointed or re-elected to retire from office at the Company's annual general meeting, together with directors appointed by the board since the last annual general meeting. Retiring directors may offer themselves for re-election. The directors retiring and offering themselves for re-election at this year's meeting are Sir John Browne, Mr H M P Miles, Sir Robin Nicholson, Mr R L Olver and Sir Ian Prosser. Dr B E Grote is standing for election by the shareholders. The biographies of the directors and the secretary are set out below. P D Sutherland, SC -- Peter Sutherland (54) rejoined BP's board in 1995 having previously been a non-executive director from 1990 to 1993. He was appointed chairman of BP in May 1997. He is chairman and managing director of Goldman Sachs International and is a non-executive director of Telefonaktiebolaget L M Ericsson, Investor AB and The Royal Bank of Scotland. 79
Sir Ian Prosser -- Sir Ian (57) joined BP's board in 1997 and was appointed deputy chairman in February 1999. He is chairman of Bass, a non-executive director of GlaxoSmithKline and a vice president of the Council of the Brewers and Licensed Retailers Association. Sir John Browne, FREng -- Sir John (53) was appointed an executive director of BP in 1991 and group chief executive in 1995. He is a non-executive director of Goldman Sachs Group and Intel Corporation, a trustee of the British Museum and a member of the supervisory board of DaimlerChryser. He is also vice president and a member of the board of the Prince of Wales Business Leaders Forum. Dr J G S Buchanan -- John Buchanan (57), chief financial officer, was appointed an executive director of BP in 1996. He is a non-executive director of Boots and a member of the UK Accounting Standards Board. R F Chase -- Rodney Chase (57), deputy group chief executive, was appointed an executive director of BP in 1992. He is a non-executive director of Diageo and the BOC Group. W D Ford -- Doug Ford (57), chief executive, refining and marketing, was appointed an executive director of BP Amoco in January 2000. Before the merger of BP and Amoco he had been an executive vice president of Amoco since 1993. He is a non-executive director of USG Corporation. Dr C S Gibson-Smith -- Chris Gibson-Smith (55), executive director, policies and technology, was appointed an executive director of BP in 1997. He is a non-executive director of Lloyds TSB. Dr B E Grote -- Byron Grote (52), chief executive, chemicals, was appointed an executive director of BP Amoco in August 2000. From 1998 until May 2000 he was vice chairman of the UK Government's Public Services Productivity Panel. R L Olver -- Dick Olver (54), chief executive, exploration and production, was appointed an executive director of BP in January 1998. He is a non-executive director of Reuters Group. R S Block -- Ruth Block (70) joined Amoco's board in 1986. She retired as executive vice president and chief insurance officer of The Equitable in 1987. She is a non-executive director of Ecolab and 35 Alliance Capital Mutual Funds. J H Bryan -- John Bryan (64) joined Amoco's board in 1982. He is chairman of Sara Lee Corporation and a non-executive director of Bank One Corporation, General Motors Corporation and Goldman Sachs. E B Davis, Jr -- Erroll B Davis, Jr (56) joined Amoco's board in 1991. He is chairman, president and chief executive officer of Alliant Energy. He is a non-executive of PPG Industries and a member of the American Society of Corporate Executives, Association of Edison Illuminating Companies, the Wisconsin Association of Manufacturers and Commerce, the Edison Electric Institute and the Electric Power Research Institute. He is also chairman of the board of trustees of Carnegie Mellon University. R J Ferris -- Richard Ferris (64) joined Amoco's board in 1981. He is a non-executive director of The Proctor & Gamble Company. C F Knight -- Charles Knight (65) joined BP's board in 1987. He is chairman of Emerson Electric and is a non-executive director of Anheuser-Busch, Morgan Stanley Dean Witter, SBC Communications and IBM. F A Maljers -- Floris Maljers (67) joined Amoco's board in 1994. He is a member of the supervisory boards of SHV Holding and Vendex N.V. He is chairman of the supervisory boards of KLM Royal Dutch Airlines, the Amsterdam Concertgebouw N.V. and Rotterdam School of Management, Erasmus University. Dr W E Massey -- Walter Massey (62) rejoined Amoco's board in 1993 having previously been a director from 1983 to 1991. He is president of Morehouse College and is a non-executive director of Motorola, Bank of America, McDonald's Corporation, the Mellon Foundation and the Commonwealth Fund. H M P Miles, OBE -- Michael Miles (64) joined BP's board in 1994. He is chairman of Johnson Matthey and a non-executive director of ING Baring Holdings and Balfour Beatty. Sir Robin Nicholson, F Eng, FRS -- Sir Robin (66) joined BP's board in 1987. He is a non-executive director of Rolls-Royce and served as a member of the UK Government's Council for Science and Technology from its inception in 1993 until 2000. 80
M H Wilson -- Michael Wilson (63) joined Amoco's board in 1993. He is chairman and chief executive officer of RT Capital Management and a non-executive director of Manufacturers Life Insurance Company. Sir Robert Wilson, KCMG -- Sir Robert (57) joined BP's board in July 1998. He is chairman of Rio Tinto and a non-executive director of Diageo. The Lord Wright of Richmond, GCMG -- Lord Wright (69) joined BP's board in 1991, having been Permanent Under-Secretary and Head of the UK Diplomatic Service. He was a non-executive director of De La Rue until July 2000. J C Hanratty -- Judith Hanratty (57) joined BP in London in 1986 and was appointed company secretary in 1994. Miss Hanratty reports to the non-executive Chairman and is not part of executive management. She provides senior governance and legal counsel to the Board. She is a member of the Competition Commission, the Takeover Panel, the Council of Lloyd's of London and of the Lloyd's Market Board. A barrister, she is also a governor of the College of Law. COMPENSATION The Remuneration Committee determines the terms of engagement and remuneration of the executive directors. Reward Philosophy The remuneration of executive directors in BP is based on the following guiding principles: -- Total rewards will be set at levels to attract, motivate and retain high-calibre and high-potential staff within a competitive global market -- Total potential rewards will be earned through achievement of demanding performance targets based on measures which will represent the best interests of shareholders in the short, medium and long term -- Incentive plans, performance targets and conditions will be structured to be robust through all stages of the business cycle -- Overall levels of reward for meeting business targets will be competitive within a global market, while outstanding rewards will only be earned for delivering world-class results -- Remuneration policies and incentive plans will be designed to meet the highest standards of international practice. There are three elements of executive remuneration: performance-based components -- long-term; performance based components -- short-term; and fixed components. These are described in the following paragraphs. Performance-based Components -- Long-term The Executive Directors' Long Term Incentive Plan (EDLTIP) was adopted by shareholders at the Annual General Meeting in April 2000 to provide long-term incentives specifically for the executive directors. The Plan has three elements: Share Element The share element focuses on BP's performance against 'oil majors' over a period of three years. The specific performance measures and comparator companies are reviewed and approved annually by the Remuneration Committee. Performance units will be granted at the beginning of the period and converted to an award of shares at the end of the period based on performance against oil majors. The performance conditions and performance periods are similar to the Long Term Performance Plan (LTPP). The first grant under the EDLTIP will be made in 2001. The maximum award can be made only when performance has been ahead of the peer group on all measures. No award is made if performance is below median. After the award is made, shares are held in trust for three years before they are released to the individual. 81
Share Option Element The option element is reflective of BP's performance relative to a wide selection of global majors. The Remuneration Committee will take into account the ranking of the company's total shareholder return (TSR) against the TSR of the FTSE Global 100 group of companies over the three-year period preceding the date of grant. There are no further performance conditions on vesting. Cash Element The Remuneration Committee may, in special circumstances, grant cash-based rather than share-based incentives. This element was not used in 2000. Performance-based Components -- Short-term Annual Bonus Bonus targets are a mix of demanding financial targets and leadership objectives relating to such areas as safety, environment, people and organization. The specific measures as well as the level of bonus eligibility are reviewed and set annually by the Remuneration Committee. Fixed Components Salary Fixed sum, payable monthly in cash. Salaries are reviewed periodically in line with global markets. The appropriate survey groups are defined and analysed by a leading remuneration consultancy. Pension Executive directors are eligible to participate in the appropriate pension schemes applicable in their home countries. Benefits and Other Share Schemes Executive directors are eligible to participate in regular employee benefit plans applicable in their home countries, including health and life insurance. They are also eligible to participate in all-employee share schemes and savings plans applicable in their home countries. Resettlement Allowance Expatriates may receive a resettlement allowance for a limited period. 2000 Remuneration for Executive Directors <TABLE> <CAPTION> Shares Performance awarded units granted under Share 2000 annual Benefits Summary of under 2000-2002 1997-1999 option performance and other remuneration LTPP(a) LTPP(b) grants(c) bonus Salary emoluments 2000 total 1999 total --------------- --------- ------ ----------- ------ ---------- ---------- ---------- ($ thousand) <S> <C> <C> <C> <C> <C> <C> <C> <C> Sir John Browne..... 280,000 527,600 408,522 1,396 1,231 135 2,762 2,351 Dr J G S Buchanan... 154,000 323,400 75,189 771 680 76 1,527 1,400 R F Chase........... 174,000 329,800 85,215 873 770 80 1,723 1,552 W D Ford............ 132,000 -- 232,500 703 620 546(d) 1,869 -- Dr C S Gibson-Smith. 140,000 285,800 68,505 702 619 108 1,429 1,231 Dr B E Grote (e).... -- -- -- 255 225 171(d) 651 -- R L Olver........... 147,000 285,800 71,847 736 649 66 1,451 1,251 Directors leaving the board in 2000 H L Fuller.......... -- -- 1,633,620 -- 168 176 344 2,434 B K Sanderson....... -- 329,800 -- 578 510 947(f) 2,035 1,433 - ------------ </TABLE> The table above represents remuneration received by executive directors in the 2000 financial year, with the exception of the 2000 annual bonus which was earned in 2000 but paid in 2001. A conversion rate of (pound)1 = $1.51 has been used for 2000, (pound)1 = $1.62 for 1999. 82
- ---------- (a) Performance units granted under the 2000-2002 LTPP are converted to shares at the end of the performance period. Maximum of two shares per performance unit. (b) Gross award of shares. Sufficient shares are sold to pay for tax applicable. Remaining shares are held in trust until 2003 when they are released to the individual. (c) Options granted in May 2000 have a grant price of(pound)5.99 ($9.04). (d) Includes resettlement allowance for Mr Ford and Dr Grote of $540,000 and $171,000 respectively. (e) Includes remuneration received since appointment as executive director on August 3, 2000. (f) Includes ex gratia payment of $679,500 and payment for unused leave of $169,875. Executive Directors' Long-term Incentives Long Term Performance Plan (LTPP) and Share Element The 2000 award relates to the 1997-1999 LTPP and the 2001 award relates to the 1998-2000 LTPP. The shares upon award have a minimum three years' retention in trust and no shares will be released until the director has a personal holding of BP shares equivalent to 5 x base salary. <TABLE> <CAPTION> Performance period of Plan 1997-1999 1998-2000 1999-2001 2000-2002 --------------- --------------- --------------- --------------- Year of award 2000 2001 2002 2003 --------------- --------------- --------------- --------------- Performance measures (a) SHRAM SHRAM SHRAM, EPS SHRAM, EPS and ROACE and ROACE --------------- --------------- --------------- --------------- Actual award Actual award Maximum Maximum award award (shares) (value)(b) (shares) (value)(c) (shares) (shares) ------ ------ ------ ------ ------ ------ ($ thousand) ($ thousand) <S> <C> <C> <C> <C> <C> <C> Current executive directors Sir John Browne............. 527,600 3,649 532,600 4,356 540,000 560,000 Dr J G S Buchanan........... 323,400 2,237 0(d) -- 320,000 308,000 R F Chase................... 329,800 2,281 339,000 2,773 360,000 348,000 W D Ford (e)................ -- -- -- -- -- 264,000 Dr C S Gibson-Smith......... 285,800 1,977 297,400 2,432 288,000 280,000 Dr B E Grote (e)............ -- -- -- -- -- -- R L Olver................... 285,800 1,977 297,400 2,432 288,000 294,000 Former executive directors H L Fuller.................. -- -- -- -- 270,000 -- B K Sanderson............... 329,000 2,281 339,000 2,773 320,000 -- K R Seal.................... 54,200 375 -- -- -- -- Dr R W H Stomberg........... 54,200 375 -- -- -- -- </TABLE> - ---------- (a) Shareholder return against the market (SHRAM), earnings per share (EPS), return on average capital employed (ROACE). In order to assess current performance on a consistent basis with past performance and a basis comparable with major competitors, EPS and ROACE in 2000 and going forward will be calculated on a pro forma basis, adjusted for special items. The pro forma basis excludes acquisition amortization and for operating capital employed it excludes the fixed asset revaluation adjustment and goodwill resulting from the ARCO and Burmah Castrol acquisitions. Acquisition amortization is the depreciation relating to the fixed asset revaluation adjustment and amortization of goodwill consequent upon these acquisitions. Special items are non-recurring charges and credits that are not classified as exceptional under UK GAAP. (b) Based on average market price on date of award ((pound)4.58/$6.92 at(pound)1 = $1.51). (c) Based on average market price on date of award ((pound)5.68/$8.18 at (pound)1 = $1.44. (d) Dr. Buchanan elected to defer consideration of his award under the 1998-2000 LTPP. Therefore the Remuneration Committee will not determine whether an award should be made to him until 2004. The Committee noted that had it made an award to Dr. Buchanan on the same basis as the other executive directors, the award would have been 319,800 shares with a value of $2,616,000. (e) This reflects Plans since their appointment as executive directors in 2000. 83
BP's performance is assessed in terms of three-year shareholder return against the market (SHRAM) in relation to the following companies: Chevron, ENI, ExxonMobil, Repsol YPF, Royal Dutch Shell group, Texaco and TotalFinaElf. BP's SHRAM for the 1997-1999 Plan was +15% compared with -5% for its highest ranking competitor. Based on this outcome the Remuneration Committee made the maximum award of shares to executive directors. An initial assessment of BP's SHRAM for the 1998-2000 Plan gives a return of +7% compared with +4% for its highest ranking competitor. On the basis of this analysis the Remuneration Committee expects to make a maximum award for the 1998-2000 Plan. Since 1999, the Remuneration Committee has also considered profitability and growth targets, i.e. earnings per share (EPS) and return on average capital employed (ROACE), in assessing performance. Maximum potential awards to executive directors under the 1999-2001 and 2000-2002 Plans (for which awards would be made in 2002 and 2003) are set out above. Share Option Element and Other Option Schemes Option grants in 2000 were made taking into consideration the ranking of the company's total shareholder return (TSR) against the TSR of the FTSE Global 100 group of companies over the three-year period from January 1, 1997. Options granted vest over three years (one-third each after one, two and three years respectively) and have a life of seven years after grant. Grants to Mr Fuller and Mr Ford were made according to the terms of the BP and Amoco merger agreement and under the BP share option plan which has minor differences in rules. <TABLE> <CAPTION> At January 1, 2000 At Dates from Directors' executive or on December 31, Average which share options (a) appointment Granted Exercised 2000 option price(b) exercisable Expiry dates ----------- ------- --------- ----------- ------------ ------------ ------------ ((pound)) <S> <C> <C> <C> <C> <C> <C> <C> Sir John Browne....... -- 408,522 -- 408,522 5.99 5/15/01 5/15/07 Dr J G S Buchanan..... -- 75,189 -- 75,189 5.99 5/15/01 5/15/07 R F Chase............. -- 85,215 -- 85,215 5.99 5/15/01 5/15/07 W D Ford.............. 4,536,444 232,500(c) 476,400(d) 4,292,544 3.46 3/22/95-3/28/02 3/24/04-3/27/10 Dr C S Gibson-Smith... -- 68,505 -- 68,505 5.99 5/15/01 5/15/07 Dr B E Grote (e)...... 138,024(f) -- -- 138,024 5.65 3/15/00-3/28/02 3/14/09-3/27/10 R L Olver............. -- 71,847 -- 71,847 5.99 5/15/01 5/15/07 Director leaving the board in 2000 At January 1, 2000 Granted Exercised On retirement --------------- -------- --------- ------------- H L Fuller.......... 15,062,244 1,633,620(c) -- 16,695,864 </TABLE> - ---------- (a) All options in the above table are denoted in BP ordinary shares. Mr Ford and Dr Grote hold ADSs; the above numbers and prices reflect calculated equivalents. (b) These are the weighted average prices applicable to all shares under option at the end of the year. Full details of directors' shareholdings and options are available for inspection in the company's register of directors' interests. (c) Mr Fuller's and Mr Ford's 2000 option grants were governed by the terms of the BP and Amoco merger agreement and were granted at equivalent of (pound)5.40 at (pound)1 = $1.51. (d) Exercised as 79,400 ADSs at $21.70 (market price at date of exercise $56). (e) In addition to the above, Dr Grote holds 191,600 SARs at an average grant price of $21.55. The relevant market price for these at December 31, 2000 was $47.87. (f) On appointment on August 3, 2000. 84
<TABLE> <CAPTION> At At Dates from January 1, December 31, Average which Directors' SAYE 2000 Granted Exercised 2000 option price(a) exercisable Expiry dates share options ----------- ------- --------- ----------- ------------ ------------ ------------ ((pound)) <S> <C> <C> <C> <C> <C> <C> <C> Sir John Browne...... 5,968 -- -- 5,968 2.89 9/1/02 2/28/03 Dr J G S Buchanan.... 7,728 -- 2,142(b) 5,586 3.50 9/1/01 2/28/05 R F Chase............ 9,324 3,388 9,324(c) 3,388 4.98 9/1/05 2/28/06 Dr C S Gibson-Smith.. 2,154 -- -- 2,154 4.49 9/1/04 2/28/05 R L Olver............ 6,856 -- -- 6,856 2.60 9/1/01 2/28/03 Director leaving the board in 2000 At On retirement January 1, September 30, 2000 Granted Exercised 2000 --------- ------- --------- ------------ B K Sanderson........ 4,250 -- 1,864(d) 2,386 </TABLE> - ---------- (a) These are the weighted average prices applicable to all shares under option at the end of the year. Full details of directors' shareholdings and options are available for inspection in the company's register of directors' interests. (b) Exercised at(pound)1.61 (market price at date of exercise(pound)4.66). (c) Exercised at(pound)1.85 (market price at date of exercise(pound)6.55). (d) Exercised at(pound)1.85 (market price at date of exercise(pound)6.47). Annual Bonus for 2000 Executive directors were eligible for an annual bonus, with a target of 70% of base salary and a stretch level of 105% of salary for substantially exceeding targets. Outstanding performance may be recognized by bonus payments in excess of the stretch level at the discretion of the Remuneration Committee. Executive directors' bonus awards for 2000 were based on a mix of financial targets and leadership objectives established at the start of the year. Each of the financial targets and leadership objectives was assessed and 162 points were achieved compared to a target level of performance of 100 points. Results Significantly Exceeded Target The company achieved continued industry leadership in ROACE and led the oil super-majors on EPS growth. It reduced by $2 billion the combined cost structure of the enlarged Group. Excellent progress was made on leadership objectives. Targets on safety, environment, restructuring, reserves, discoveries, capital savings, people, regional governance and brand were all achieved and, in several cases, exceeded. Based on the above performance, the committee expects to award bonuses as indicated in the table opposite totalling $6 million for the executive directors as a group for 2000. Salary There were no increases in base salaries for the current executive directors during 2000. <TABLE> <CAPTION> Year ended Year ended December 31, 2000(a) December 31, 1999(b) ----------------- ----------------- <S> <C> <C> Bonus rating.................................... 162 148 ($ thousand) Sir John Browne................................. 1,396 1,137 Dr J G S Buchanan............................... 771 673 R F Chase....................................... 873 754 W D Ford........................................ 703 -- Dr C S Gibson-Smith............................. 702 590 Dr B E Grote.................................... 255(c) -- R L Olver....................................... 736 596 Director leaving the board in 2000 B K Sanderson................................... 578 685 </TABLE> - ---------- (a) 2000 bonus received in 2001 at an exchange rate of(pound)1 = $1.51. (b) 1999 bonus received in 2000 at an exchange rate of(pound)1 = $1.62. (c) From date of appointment on August 3, 2000. 85
Pensions Pension and other benefits have regard to competitor practice in the home country of each senior executive. UK directors are eligible to join the BP Pension Scheme, which offers Inland Revenue-approved retirement benefits based on final salary. The Scheme is the principal section of the BP Pension Fund, the latter being set up under trust deed. Contributions to the Fund are made on the advice of the actuary appointed by the Trustee. No company contributions in respect of the BP Pension Scheme were made in 2000. Scheme members' core benefits, which are non-contributory, comprise a pension accrual rate of 1/60th of basic salary for each year of service, up to a limit of two-thirds of final basic salary; a lump-sum death-in-service benefit of three times salary; and a dependants' benefit of two-thirds of actual or prospective pension. The link between the Scheme pension and the basic state pension ceased for all members on May 1, 2000. Directors who are members of the Scheme accrue pension at the enhanced rate of 2/60ths of their final basic salary for each year of service as executive directors (up to the same two-thirds limit) on a non-contributory basis. Normal retirement age is 60, but Scheme members who have 30 or more years' pensionable service at age 55 can opt to retire early without an actuarial reduction to their pension. Pensions payable from the Fund are guaranteed to increase in line with annual movements in the Retail Price Index, to a maximum of 5% a year. None of the executive directors is affected by the 'pensions earnings cap'. All current US directors participate in the BP Retirement Accumulation Plan. Under this retirement plan, the amount of the annuity which they are eligible to receive on a single-life basis is determined under a cash balance formula. This plan was created in 2000 and supersedes earlier Group pension and cash balance plans. However, those employees who satisfied certain age and service conditions at the date of transition to the BP Retirement Accumulation Plan were provided with a minimum benefit equal to those which they would have earned under the previous pension arrangements. These 'grandfathering' arrangements apply to Mr Ford and Mr Fuller. Their figures have been disclosed on this basis. In line with US tax regulations, benefits are provided as appropriate through a combination of tax qualified and restoration/ non-qualified plans. Under the 'grandfathering' arrangement, the annuity benefit formula (including a percentage of US Social Security benefits) is calculated at 1.67% x years of participation x average annual earnings. Such earnings for plan purposes are determined by taking separately the three highest consecutive calendar years' earnings from salary and the three highest consecutive calendar years' bonus awards during the 10 years preceding retirement. The maximum annuity is 60% of such average earnings. Normal pensionable age is 65. There is no actuarial reduction to the pension which becomes payable between age 60 and 65, but a reduction of 5% a year is applied if paid between age 50 and 59. Dr Grote is not subject to 'grandfathering'. His benefit is therefore determined by the cash balance formula whereby each year of service accrues a credit in a current account based on a sliding age and service scale (minimum 4%, maximum 11% of eligible pay). The account balance earns interest on a monthly basis. Prior service has been converted into an opening account balance and is included in Dr Grote's projected pension figures. 86
<TABLE> <CAPTION> Changes in Changes in pension earned pension earned Accrued during the during the Years of service entitlement at year ended year ended Pension entitlement -- at December 31, December 31, December 31, December 31, UK executive directors(a) 2000 2000 2000(b) 1999(b) ---------------- -------------- -------------- -------------- ($ thousand) ($ thousand) ($ thousand) <S> <C> <C> <C> <C> Sir John Browne......... 34 820 (15) 252 Dr J G S Buchanan....... 31 439 15 118 R F Chase............... 36 513 (9) 128 Dr C S Gibson-Smith..... 30 387 14 95 R L Olver............... 27 409 14 115 B K Sanderson........... 36(c) 453(c) (6)(c) 63 </TABLE> - ---------- (a) An exchange rate of(pound)1 = $1.51 has been used for 2000,(pound)1 = $1.62 for 1999. (b) Excludes the impact of inflation. (c) Figures shown at date pensionable service ceased September 30, 2000. <TABLE> <CAPTION> Additional Additional pension earned pension earned Accrued during the during the Years of service entitlement at year ended year ended Pension entitlement -- at December 31, December 31, December 31, December 31, US executive directors 2000 2000 2000 1999 ---------------- -------------- -------------- -------------- ($ thousand) ($ thousand) ($ thousand) <S> <C> <C> <C> <C> H L Fuller.................. 39 1,203(a) 31 26 W D Ford.................... 30 376(b) 67(b) 36 Dr B E Grote................ 21 69 10 11 </TABLE> - ---------- (a) Mr Fuller resigned on March 31, 2000 and took a lump-sum distribution of his combined qualified and non-qualified plan benefits totalling $13,627,975. (b) Includes a temporary annuity payable until age 62 of $6,869. Executive Directors' Shareholdings <TABLE> <CAPTION> Change in At directors' January 1, 2000 interests from Executive directors' interests in At or on December 31, 2000 BP ordinary shares or calculated December 31, 2000 appointment to March 30, 2001 equivalents ----------------- --------------- ----------------- <S> <C> <C> <C> Current directors Sir John Browne........................ 1,069,445(a) 959,842 319,560 Dr J G S Buchanan...................... 721,312 513,490 4 R F Chase.............................. 709,325 568,630 203,400 W D Ford............................... 311,358(b) 284,772(b) -- Dr C S Gibson-Smith.................... 491,395 312,189 178,440 Dr B E Grote........................... 431,598(b) 428,250(b)(c) 148,200 R L Olver.............................. 421,910 255,590 178,440 </TABLE> <TABLE> <CAPTION> At On retirement January 1, 2000 --------------- --------------- <S> <C> <C> Directors leaving the board in 2000 H L Fuller............................... 1,307,295(b)(d) 1,307,295 B K Sanderson............................ 720,858(e) 518,814 </TABLE> - ---------- (a) Includes 50,368 ordinary shares held as ADSs. (b) Held as ADSs. (c) On appointment on August 3, 2000. (d) On retirement on March 31, 2000. (e) On retirement on September 30, 2000. 87
In disclosing the above interests to the company under the Companies Act 1985, directors did not distinguish their beneficial and non-beneficial interests. All executive directors are deemed to have an interest in such shares of the company held from time to time by BP QUEST Company Limited to facilitate the operation of the company's SAYE option scheme. Service Contracts All UK executive directors appointed since 1996 hold a contract of service which includes a one-year period of notice. Sir John Browne and Mr Chase were appointed prior to 1996 and have contracts with a two-year notice period. The board does not consider it in shareholders' interests to renegotiate these contracts. Mr Ford's current secondment commenced on January 1, 2000 and can be terminated on one month's notice. His underlying US employment agreement with BP Amoco Corporation has a two-month notice period. If his contract is terminated by the company without cause, it is required to pay him $1 million per annum (pro rated for part years) for each year between the date of severance and January 21, 2004. As an expatriate, Mr Ford also receives a resettlement allowance for the first three years of his secondment. Dr Grote's current UK secondment to BP began on August 3, 2000 and can be terminated on one month's notice. His underlying US employment agreement with BP Exploration (Alaska) Inc. has a one-year notice period. As an expatriate, Dr Grote receives a resettlement allowance for the first three years of his secondment. Reward Policy for 2001 During the latter part of 2000, the Remuneration Committee reviewed the remuneration of all existing executive directors relative to a global set of comparator companies. Independent consultants, who are not employed elsewhere in the company, assisted in this work. As a result of this review the committee agreed that: - -- the overall existing framework of total direct compensation is appropriate for 2001. - -- the limits for both the share element and the share option element of the Executive Director Long Term Incentive Plan (EDLTIP) that were agreed with shareholders are sufficient to meet the guiding principles of the reward philosophy. - -- the performance conditions applied to the share element of the EDLTIP commencing 2001 will remain the same as those under the LTPP for the period starting 2000. The committee will be reviewing the performance conditions for future plans during 2001. - -- it would grant share options under the EDLTIP using a primary measure the Company's performance relative to the FTSE Global 100 group of companies over the past three years. The following options were granted in February 2001 at a price of (pound)5.67 ($8.22) per ordinary share and have terms and conditions similar to the 2000 grant noted under the heading 'Share Option Element and Other Option Schemes'. <TABLE> <CAPTION> <S> <C> <C> Sir John Browne 1,269,843 BP ordinary shares Dr J G S Buchanan 253,971 BP ordinary shares Mr R F Chase 312,171 BP ordinary shares Mr R L Olver 260,319 BP ordinary shares Mr W D Ford 43,506 BP ADSs (equivalent to 261,036 ordinary shares) Dr B E Grote 40,182 BP ADSs (equivalent to 241,092 ordinary shares) </TABLE> - -- annual bonus targets will be set at 100% of salary for all executive directors except Sir John Browne who will have a target of 110%. The maximum bonus eligibility given outstanding performance will be 150% for all executive directors. - -- base salaries have been increased in line with global comparator companies with effect from April 1, 2001. 88
Remuneration of Non-Executive Directors The articles of association provide that the remuneration paid to non-executive directors shall be determined by the board within the limits set by the shareholders. Non-executive directors do not have service contracts with the company. During 2000 the non-executive chairman of BP received a fee of $242,000 ((pound)160,000). The non-executive directors of BP received an annual fee of $60,000 ((pound)40,000) plus an allowance of $5,000 ((pound)3,000) for each occasion on which a director travels across the Atlantic for a board meeting or committee meeting. During 2000 the board met eight times, five times in the UK, twice in the USA and once in France. Committee meetings are held in conjunction with board meetings whenever feasible. Details of individual fees and allowances are set out in the table below. The fees paid to non-executive directors have been increased, within the limits set by shareholders, with effect from April 1, 2001. <TABLE> <CAPTION> Year ended Year ended December 31, 2000(a) December 31, 1999(b) Current directors ----------------- ----------------- ($ thousands) <S> <C> <C> R S Block........................................ 74 89 J H Bryan........................................ 88 84 E B Davis, Jr.................................... 88 89 R J Ferris....................................... 79 84 C F Knight....................................... 83 79 F A Maljers...................................... 65 70 Dr W E Massey.................................... 83 89 H M P Miles...................................... 69 79 Sir Robin Nicholson.............................. 69(c) 79(d) Sir Ian Prosser.................................. 121 122 P D Sutherland................................... 242(e) 259(f) M H Wilson....................................... 88 94 Sir Robert Wilson................................ 69 79 The Lord Wright of Richmond...................... 69(g) 75(h) ------ ------ 1,287 1,371 ====== ====== </TABLE> - ---------- (a) Sterling payments converted at the average 2000 exchange rate of(pound)1 = $1.51. (b) Sterling payments converted at the average 1999 exchange rate of(pound)1 = $1.62. (c) Also received $30,200 ((pound)20,000 converted at the average 2000 exchange rate of(pound)1 = $1.51) for serving on the Technology Advisory Council. (d) Also received $32,400 ((pound)20,000 converted at the average 1999 exchange rate of(pound)1 = $1.62) for serving on the Technology Advisory Council. (e) Also received other benefits of $2,292 ((pound)1,518 converted at the average 2000 exchange rate of(pound)1 = $1.51). (f) Also received other remuneration and benefits of $9,849 ((pound)6,080 converted at the average 1999 exchange rate of(pound)1 = $1.62). (g) Also received $1,812 ((pound)1,200 converted at the average 2000 exchange rate of (pound)1 = $1.51) for serving as a director of BP Pensions Trustees Limited. (h) Also received $1,458 ((pound)900 converted at the average 1999 exchange rate of (pound)1 = $1.62) for serving as a director of BP Pensions Trustees Limited. 89
BOARD PRACTICES <TABLE> <CAPTION> Directors' Terms of Office Period during which the director has served in Date of expiration of this office (from current term of office appointment to April 2001 ---------------------- ------------------------- <S> <C> <C> R S Block (a)............................... Retires April 2001 2 years 4 months Sir John Browne............................. April 2001 9 years 7 months J H Bryan (a)............................... April 2002 2 years 4 months Dr J G S Buchanan........................... April 2003 4 years 7 months Mr R F Chase................................ April 2003 9 years 1 month E B Davis, Jr (a)........................... April 2002 2 years 4 months R J Ferris (a).............................. April 2002 2 years 4 months W D Ford.................................... April 2003 1 year 4 months Dr C S Gibson-Smith......................... Retires April 2001 3 years 8 months Dr B E Grote................................ April 2001 9 months C F Knight.................................. April 2003 13 years 7 months F A Maljers (a)............................. April 2002 2 years 4 months W E Massey (a).............................. April 2002 2 years 4 months H M P Miles................................. April 2001 6 years 11 months Sir Robin Nicholson......................... April 2001 13 years 7 months R L Olver................................... April 2001 3 years 4 months Sir Ian Prosser............................. April 2001 4 years P D Sutherland.............................. April 2002 5 years 8 months M H Wilson (a).............................. April 2002 2 years 4 months Sir Robert Wilson........................... April 2002 2 years 9 months Lord Wright of Richmond..................... Retires April 2001 9 years 7 months </TABLE> - ---------- (a) Does not count service on the board of Amoco Corporation. Directors' Service Contracts Providing for Benefits upon Termination of Employment Non-executive directors do not have service contracts with the Company; they are not employees of the Company. Non-executive directors are not entitled to any benefits on termination of office. Executive directors are employees of the Company or one of its subsidiaries under a variety of contracts of service. The standard contract of service for executive directors provides for one year's notice to be given of termination of the contract or payment of one year's salary in lieu of notice. There are three exceptions to this standard contract. Sir John Browne and Mr R F Chase have contracts that provide for two year's notice of termination. Mr W D Ford's employment agreement with BP Amoco Corporation has a two-month notice period. If the Company dismisses Mr Ford without cause, it is required to pay him $1 million per annum for each year between the date of severance and January 21, 2004. Corporate Governance BP's board policies recognize that the board has a separate and unique role as the link in the chain of authority between the shareholders and the group chief executive. In addition, they acknowledge in a number of ways the dual role played under the unitary board system by the group chief executive and executive directors, as both members of the board and leaders of the executive management. For example, they require a majority of the board to be composed of non-executive directors. Moreover, they delegate all aspects of the relationship between the board and the group chief executive to the non-executive directors. For the same reason, the policies require the chairman and deputy chairman to be non-executive directors. Following the retirement of co-chairman Mr Fuller on March 31, 2000, the office of chairman has been held by a non-executive director, Mr Sutherland. Sir Ian Prosser is deputy chairman and holds the role of senior independent non-executive director required by the Combined Code on Corporate Governance. Finally, the company secretary reports to the non-executive chairman and is not part of the executive management. Relationship with Shareholders The policies stress the importance of the relationship between the board and the shareholders. In them, the board acknowledges that its role is to represent and promote the interests of shareholders. They recognize that the board is accountable to shareholders for the performance and activities of the group (including the system of internal control and the review of its effectiveness). 90
The board is required to be proactive in obtaining an understanding of shareholder preferences and to evaluate systematically the economic, political, social and other matters that may influence or affect the interests of its shareholders. To ensure that shareholders have the regular opportunity to reassess their choice of directors, directors are required to retire every three years and stand for re-election. The formal channels of communication by which the board accounts to shareholders for the overall performance of the company's business activity are the annual report and accounts, the form 20-F report filed annually with the US Securities and Exchange Commission and the quarterly announcements made through the stock exchanges on which the shares are listed. In addition, at the annual general meeting of shareholders an extensive presentation is given about the business, its performance and future prospects. At that meeting there is the opportunity for shareholders to ask questions or give their views to directors. With approximately 1.1 million shareholders, however, many of whom are resident outside the UK, opportunities for dialogue with the board at annual general meetings are limited. All proxy votes at shareholder meetings are counted because votes on all matters except procedural ones are taken by way of a poll. The chairmen of the Remuneration and Nomination Committees (and all other committee chairmen except the Audit Committee chairman) were present at the 2000 annual general meeting to answer questions. Presentations are made to representatives of the investment community at appropriate intervals in both the UK and the USA and are simultaneously made available to shareholders by live broadcast over the Internet or open conference call. The constructive use of technology for communication with shareholders is continually evaluated and implemented as appropriate. Board Process The board has laid down rules for its own activities in a board process policy that covers the conduct of members at meetings; the cycle of board activities and the setting of agendas; the provision of information to the board; board officers and their roles; board committees, their tasks and composition; qualifications for board membership and the process of the Nomination Committee; the remuneration of non-executive directors; the appointment and role of the company secretary; the process for directors to obtain independent advice and the assessment of the board's performance. The board process policy places responsibility for implementation of this policy, including training of directors, on the chairman. The policy recognizes that the board's capacity, as a group, is limited. It therefore reserves to itself the making of broad policy decisions, delegating the more detailed considerations involved in meeting its stated requirements either to its committees and officers, in the case of its own processes, or to the group chief executive, in the case of the management of the company's business activity. On internal control, for example, the board is responsible for establishing general policy and for monitoring whether the group chief executive carries it out. The relationship between the board and the group chief executive is critical to the board's work. The policy allocates the tasks of monitoring executive actions and assessing reward to the following committees: - -- Chairman's Committee (chairman and all non-executive directors) - organization and succession planning and overall performance assessment. - -- Audit Committee (six non-executive directors) - monitoring all reporting, accounting, control and the financial aspects of the executive management's activities (further details of which are set forth below). - -- Ethics and Environment Assurance Committee (five non-executive directors) - monitoring the non-financial aspects of the executive management's activities. - -- Remuneration Committee (six non-executive directors) - determining performance contracts and targets and the structure of the rewards for the group chief executive and the executive directors (further details of which are set forth below). In addition, there is a Nomination Committee, which comprises the non-executive chairman, the group chief executive and three non-executive directors. The qualification for membership of the board includes a requirement that non-executive directors be free from any relationship with the executive management of the company that could materially interfere with the exercise of their independent judgement. In the board's view, all non-executive directors fulfil this requirement. 91
Under the articles of association, all directors are subject to election by shareholders at the first opportunity after their appointment and to re-election thereafter at intervals of no more than three years. Names submitted to shareholders for election in 2000 were accompanied by biographical details. In carrying out its work, the board has to exercise judgement about how best to further the interests of shareholders. Given the uncertainties inherent in the future of business activity, the board's work is designed to maximize the expected value of the shareholders' interest in the group, not to eliminate the possibility of any adverse outcomes for shareholders. Board/Executive Relationship The board/executive relationship policy sets out how the board delegates authority to the group chief executive and the extent of that authority. In its goals policy, the board states the long-term outcome it expects the group chief executive to deliver. The restrictions on the manner in which the group chief executive may achieve the required results are set out in the executive limitations policy, which addresses ethics, health, safety, the environment, financial distress, internal control, risk preferences, treatment of employees and political considerations. On all these matters, the board's role is to set general policy and to monitor the implementation of its policy by the group chief executive. The group chief executive explains how he intends to deliver the required outcome in medium-term and annual plans, the latter of which includes a comprehensive assessment of the risks to delivery. Progress towards the expected outcome is set out in a monthly report that covers actual results and a forecast of results for the current year. The board reviews this report at each meeting. The board/executive relationship policy also sets out how the group chief executive's performance will be monitored and recognizes that, in the multitude of changing circumstances, judgement is always involved. The group chief executive is obliged through dialogue and systematic review to discuss with the board all material matters currently or prospectively affecting the company and its performance and all strategic projects or developments. This specifically includes any materially under-performing business activities and actions that breach the executive limitations policy. This dialogue is meant to be a key feature of the relationship and an important aspect of board work. The chairman has responsibility on behalf of the board between meetings for ensuring the integrity and effectiveness of the board/executive relationship. The systems set out in the board/executive relationship policy are designed to manage rather than eliminate the risk of failure to achieve the board goals policy or observe the executive limitations policy. They provide reasonable, not absolute, assurance against material misstatement or loss. Audit Committee The Committee is comprised of 6 non-executive directors: Sir Ian Prosser (Chairman), Mr J H Bryan, Mr E B Davis Jr, Mr H M P Miles, Mr M H Wilson and Sir Robert Wilson. The Secretary of the Committee, Miss Judith Hanratty (Company Secretary) is independent of the executive management of the Company and reports to the non-executive Chairman. The tasks given to the Audit Committee by the Board Governance Policies are: - -- To monitor systematically and obtain assurance that the legally required standards of disclosure are being fully and fairly observed. - -- To review all prospectuses, information and offering memoranda and other documents to be placed before shareholders and make recommendations to the Board about their adoption and publication. - -- To review all annual, quarterly and similar reports to shareholders and make recommendations to the Board about their adoption and publication. - -- To monitor systematically and obtain assurance that the Executive Limitations set out in the Board Governance Policies relating to financial matters are being observed. The Committee met six times in 2000. 92
Remuneration Committee The Committee is comprised of 6 non-executive directors: The Lord Wright of Richmond (Chairman), Mr E B Davis Jr, Mr R J Ferris, Mr C F Knight, Sir Robin Nicholson and Sir Ian Prosser. Lord Wright will retire in April 2001 and Sir Robin Nicholson will become chairman of the Committee. The Secretary of the Committee, Mr Gerrit O Aronson, is independent of the executive management of the Company and reports to the non-executive Chairman. The remuneration consultants and legal advisers for the Committee are selected by the Secretary and are required to be free from any business or other relationship with the executive management of the Company that could undermine their independence. The tasks given to the Remuneration Committee by the Board Governance Policies are: - -- To determine on behalf of the Board the terms of engagement and remuneration of the CEO and the Executive Directors and to report on those to the shareholders. - -- To determine on behalf of the Board matters of policy over which the Company has authority relating to the establishment or operation of the Company's pension scheme of which the Executive Directors and senior executives are members. - -- To nominate on behalf of the Board any trustees (or directors of corporate trustees) of such scheme. The Committee met six times in 2000. EMPLOYEES <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- <S> <C> <C> <C> <C> <C> Number of employees at December 31, 2000 Exploration and Production............. 3,300 700 5,900 6,100 16,000 Gas and Power.......................... 500 100 300 100 1,000 Refining and Marketing ................ 10,100 16,800 27,400 13,400 67,700 Chemicals.............................. 3,700 4,500 7,900 1,500 17,600 Other businesses and corporate......... 1,300 400 2,500 700 4,900 -------- -------- -------- -------- -------- 18,900 22,500 44,000 21,800 107,200 ======== ======== ======== ======== ======== 1999 Exploration and Production............. 3,700 1,150 2,800 4,850 12,500 Gas and Power.......................... 450 50 200 100 800 Refining and Marketing ................ 9,000 11,150 17,900 7,200 45,250 Chemicals.............................. 3,950 4,700 8,100 1,950 18,700 Other businesses and corporate......... 1,150 300 1,150 550 3,150 -------- -------- -------- -------- -------- 18,250 17,350 30,150 14,650 80,400 ======== ======== ======== ======== ======== 1998 Exploration and Production............. 3,650 900 7,400 6,050 18,000 Gas and Power.......................... 450 50 200 100 800 Refining and Marketing ................ 10,050 9,500 22,950 9,600 52,100 Chemicals.............................. 4,150 5,250 11,550 2,100 23,050 Other businesses and corporate......... 950 400 850 500 2,700 -------- -------- -------- -------- -------- 19,250 16,100 42,950 18,350 96,650 ======== ======== ======== ======== ======== </TABLE> Following the merger of BP and Amoco on December 31, 1998, some 19,000 employees have left the Group through severance or outsourcing arrangements. Of this total approximately 16,000 employees left in 1999. The acquisition of ARCO and Burmah Castrol during 2000 brought approximately 25,000 additional employees to the Group of which some 3,000 have left through integration and rationalization activities. 93
SHARE OWNERSHIP Directors As at March 30, 2001 the following directors of BP Amoco p.l.c. held interests in BP ordinary shares of 25 cents each or their calculated equivalent as set out below: <TABLE> <CAPTION> <S> <C> Sir John Browne...............1,389,005 Dr J G S Buchanan............. 721,316 R F Chase..................... 922,049 W D Ford...................... 238,506 Dr C S Gibson-Smith........... 669,835 Dr B E Grote.................. 579,906 R L Olver..................... 600,360 R S Block..................... 83,858 J H Bryan..................... 98,760 E B Davis, Jr................. 61,985 R J Ferris.................... 260,808 C F Knight.................... 29,647 F A Maljers................... 33,492 Dr W E Massey................. 46,836 H M P Miles................... 9,445 Sir Robin Nicholson........... 3,548 Sir Ian Prosser............... 826 P D Sutherland................ 6,897 M H Wilson.................... 43,200 Sir Robert Wilson............. 5,478 Lord Wright................... 3,996 </TABLE> As at March 30, 2001, the following directors of BP Amoco p.l.c. held options under the BP Group share option schemes for ordinary shares or their calculated equivalent as set out below: <TABLE> <CAPTION> <S> <C> Sir John Browne...............1,684,333 Dr J G S Buchanan............. 334,746 R F Chase..................... 400,774 W D Ford......................4,553,580 Dr C S Gibson-Smith........... 70,659 Dr B E Grote.................. 379,116 R L Olver..................... 339,022 </TABLE> Additional details regarding the options granted, including exercise price and expiry dates, are found in this Item under the heading `Compensation -- Share Option Element and Other Option Schemes'. Employee Share Schemes BP offers most of its employees the opportunity to acquire a shareholding in the company through savings-related and matching arrangements; the latter may be either participating share schemes or savings plans. BP also uses a long-term performance plan and the granting of share options as elements of employee remuneration. Under the BP Group Savings Related Share Option Scheme employees save monthly over a three- or five-year period towards the purchase of shares at a price fixed when the option is granted. The option price is usually set at a 20% discount to the market price at the time of grant. The option must be exercised within six months of maturity of the savings contract otherwise it lapses. The scheme is run in the UK and a number of other countries. Under the BP Group Participating Share Scheme, BP matches employees' own contribution of shares, up to a predetermined limit, all of which are then held in trust for defined periods before being released to the employee. The scheme is run in the UK and in a number of other countries. A further 20 countries implemented a participating share plan during 2000. 94
The company sponsors a number of savings plans covering most US employees. Under these plans, employees may contribute up to 18% of their salary subject to certain regulatory limits. The employee receives a dollar-for-dollar company matched contribution for the first 7% of eligible pay contributed to most of these plans on a before-tax or after-tax basis, or a combination of both. Company contributions are initially invested in BP ADS funds, but employees may transfer those amounts and may invest their own contributions in more than 200 investment options. The company's contributions vest over a period of five years. Company contributions to savings plans during the year were $101 million (1999 $95 million). During 2000, BP granted options under the BP Share Option Plan to certain categories of employees. Options were granted to heritage-Amoco employees who, under the terms of the merger agreement between BP and Amoco, must, for 1999 and 2000, be granted options on a similar basis to the arrangements under the Amoco 1991 Incentive Program. Options were also granted to certain heritage-BP US employees. The options were granted at the market price at the date of grant. There are no performance conditions attaching to these grants. The options are exercisable one or two years after the date of grant, and lapse after 10 years. Also in 2000, options were granted to non-US middle managers. The options were granted at market price at the date of grant and are not exercisable until a performance condition is satisfied. Before any options can be exercised, the total return to shareholders (share price increase with all dividends reinvested) on an investment in BP shares is required to exceed the mean total return to shareholders of a representative group of UK companies by a margin set from time to time. The performance period for each grant will normally be three years. Subject to achievement of the performance conditions, the options are exercisable between the third and tenth anniversaries of the date of grant. In accordance with their normal timetable, options were granted to ARCO employees in February 2000. All options granted prior to April 1, 1999, the date of the acquisition announcement, became exercisable immediately on completion of the acquisition in April 2000 at the discretion of the employee. Burmah Castrol employees eligible to receive options in 2000 were granted options under the BP Share Option Plan, with certain rule modifications, after completion of the acquisition. For options granted prior to the acquisition, employees were generally offered the choice of cashing out their existing options or converting them to BP share options. Pursuant to the various BP Group share option schemes, the following options for BP ordinary shares of the Company were outstanding at March 30, 2001: <TABLE> <CAPTION> Expiry Exercise Options dates of price outstanding options per share ------------ ------------ ------------ (shares) <S> <C> <C> 408,731,893 2001 to 2011 $2.25 to $9.97 </TABLE> Further details on share options appear in Item 18 -- Financial Statements - -- Note 33. 95
ITEM 7 -- MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS MAJOR SHAREHOLDERS At March 30, 2001, the Company has been notified that Morgan Guaranty Trust Company of New York, as depositary for American Depositary Shares (ADSs), holds interests through its nominee, Guaranty Nominees Limited, in 7,279,150,812 ordinary shares (32.4% of the Company's ordinary share capital). Included in this total is part of the holding of the Kuwait Investment Office (KIO). Either directly or through nominees, the KIO holds interests in 715,040,000 ordinary shares (3.18% of the Company's ordinary share capital). RELATED PARTY TRANSACTIONS The principal joint ventures and associated undertakings of the BP Group are shown in Item 18 -- Financial Statements -- Note 45. During the period to August 1, 2000 the Group sold crude oil and products totaling $2,933 million (1999 $3,398 million and 1998 $2,264 million) to the BP/Mobil European joint venture and purchased crude oil and products totaling $1,762 million (1999 $1,791 million and 1998 $1,335 million). In 2000 the Group purchased crude oil from two associated undertakings, Abu Dhabi Marine Areas and Abu Dhabi Petroleum to the value of $1,619 million (1999 $935 million and 1998 $715 million). Also during the year the Group sold chemical feedstocks totaling $718 million (1999 $460 million and 1998 $395 million) to Erdolchemie, an associated undertaking and bought petrochemicals to the value of $114 million (1999 $77 million and 1998 $76 million). In the ordinary course of its business the Group has transactions with various organizations with which certain of its directors are associated but, except as described in this report, no material transactions responsive to this item have been entered into in the period commencing January 1, 2000 to March 30, 2001. ITEM 8 -- FINANCIAL INFORMATION CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION Financial Statements See Item 18 -- Financial Statements. Dividends Our financial framework is to maintain a ratio of net debt to net debt plus equity (after adjusting for the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions) of around 20-30% and a dividend policy which aims to return to shareholders around 50% of our replacement cost profit before exceptional items after adjusting for special items and acquisition amortization, adjusted to mid-cycle business conditions. Special items are non-recurring charges and credits that are not classified as exceptional under UK GAAP. Acquisition amortization refers to depreciation relating to the fixed asset revaluation adjustment and amortization of goodwill consequent upon the ARCO and Burmah Castrol acquisitions. Mid-cycle conditions are our best estimate of likely average prices and margins over the long term. If circumstances give us a larger surplus it is anticipated that cash will either be used to fund further growth investment or be returned to shareholders. Legal Proceedings Save as disclosed in the following paragraphs, no member of the Group is a party to, and no property of a member of the Group is subject to, any pending legal proceedings which are significant to the Group. Approximately 200 lawsuits were filed in State and Federal Courts in Alaska seeking compensatory and punitive damages arising out of the Exxon Valdez oil spill in Prince William Sound in March 1989. Most of those suits named Exxon (now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies which own Alyeska. Alyeska initially responded to the spill until the response was taken over by Exxon. BP owns a 50% interest in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BP's combination with ARCO. In April 2000, that 20% interest was sold to Phillips Petroleum Company (Phillips), subject to BP's agreement to indemnify Phillips if certain liabilities exceeded a defined amount. Alyeska and its owners have settled all of the claims against them under these lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages which it has incurred. If any claims are asserted by Exxon which affect Alyeska and its owners, BP would defend the claims vigorously. 96
The Internal Revenue Service (IRS) has challenged the application of certain foreign income taxes as credits against BP Amoco Corporation's US taxes that otherwise would have been payable for the years 1980 to 1992. On June 18, 1992, the IRS issued a statutory Notice of Deficiency for additional taxes in the amount of $466 million, plus interest, relating to 1980 to 1982. BP filed a petition in the US Tax Court contesting the IRS statutory Notice of Deficiency. Trial on the matter was held in April 1995, and a decision was rendered by the US Tax Court in March 1996, in BP's favour. The IRS appealed the Tax Court's decision to the US Court of Appeals for the Seventh Circuit and on March 11, 1998, the Seventh Circuit affirmed the Tax Court's prior decision. A comparable adjustment of foreign tax credits for each year has been proposed for the years 1983 to 1992 based upon subsequent IRS audits. In November 1999, BP Amoco Corporation reached an agreement with the IRS that effectively resolves this issue at a minimal tax cost to the Company. On December 13, 1999 the parties filed a status report with the US Tax Court for the years 1983-1989 advising the Court that a basis for settlement had been reached and that final calculations were in the process of being prepared. Once these calculations are finalized, the parties expect to file an agreed decision document for the Court's final approval, which will then conclude the litigation. In April 2000, BP Exploration (Alaska) Inc. paid $416 million to settle in full certain corporation income tax claims by the State of Alaska for the years 1991-96. See ARCO's annual report on Form 10-K for the year ended December 31, 2000 for a description of litigation involving ARCO. In March 2000, ExxonMobil filed a Complaint in State Court, Los Angeles, seeking declaratory and injunctive relief and specific performance against BP, ARCO and Phillips to prevent the sale of ARCO's Alaskan business to Phillips referred to in Item 4 -- Information on the Company -- Business Overview. ExxonMobil allege that the proposed sale to Phillips breaches ExxonMobil's prior preferential rights to purchase the interests subject to an agreement between predecessors of ARCO and predecessors of ExxonMobil dated September 23, 1964. This lawsuit was dismissed on May 11, 2000. For certain information regarding environmental proceedings see Item 4 -- Environmental Protection -- United States. SIGNIFICANT CHANGES None. ITEM 9 -- THE OFFER AND LISTING Markets and Market Prices The primary market for the Company's Ordinary Shares is the London Stock Exchange. The Company's Ordinary Shares are a constituent element of the Financial Times Stock Exchange 100 Index. The Company's Ordinary Shares are also traded on stock exchanges in France, Germany, Japan and Switzerland. Trading of BP's shares on the LSE is primarily through the use of the Stock Exchange Electronic Trading Service (SETS), introduced in 1997 for the largest companies in terms of market capitalization whose primary listing is the LSE. Under SETS, buy and sell orders at specific prices may be sent to the exchange electronically by any firm which is a member of the LSE, on behalf of a client or on behalf of itself acting as a principal. The orders are then anonymously displayed in the order book. When there is a match on a 'buy' and a 'sell' order, the trade is executed and automatically reported to the LSE. Trading is continuous from 9:00 a.m. to 4:30 p.m. UK time, but in the event of a 20% movement in the share price either way the LSE may impose a temporary halt in the trading of that company's shares in the order book, to allow the market to re-establish equilibrium. Dealings in the Company's ordinary shares may also take place between an investor and a market-maker, via a member firm, outside the electronic order book. In the United States and Canada the Company's securities are traded in the form of American Depositary Shares (ADSs), for which Morgan Guaranty Trust Company of New York is the depositary (the Depositary) and transfer agent. The Depositary's address is 60 Wall Street, New York, NY 10260, USA. Each ADS represents six BP ordinary shares. ADSs are listed on the New York Stock Exchange, and are also traded on the Chicago, Pacific and Toronto Stock Exchanges. ADSs are evidenced by American Depositary Receipts, or ADRs, which may be issued in either certificated or book entry form. 97
The following table sets forth for the periods indicated the highest and lowest middle market quotations for the BP ordinary shares of The British Petroleum Company p.l.c. for 1996, 1997 and 1998, and of BP Amoco p.l.c. for 1999 and 2000. These are derived from the Daily Official List of the LSE, and the highest and lowest sales prices of ADSs as reported on the New York Stock Exchange composite tape. The information in this table has been changed to reflect the subdivision of BP ordinary shares on October 4, 1999, whereby each ordinary share of $0.50 was subdivided into two ordinary shares of $0.25. <TABLE> <CAPTION> American Depositary Ordinary shares Shares (a) --------------- --------------- High Low High Low ---- --- ---- --- (Pence) (Dollars) <S> <C> <C> <C> <C> Year ended December 31, 1996...................................... 350.75 257.25 35.94 23.63 1997...................................... 478.25 331.75 46.50 32.44 1998...................................... 484.25 368.50 48.66 36.50 1999...................................... 643.50 411.00 62.63 40.19 2000...................................... 671.00 444.50 60.63 43.13 Year ended December 31, 1999: First quarter....................... 539.50 411.00 52.66 40.19 Second quarter...................... 595.50 504.75 57.69 47.00 Third quarter....................... 642.50 532.50 61.16 52.50 Fourth quarter...................... 643.50 538.00 62.63 51.38 2000: First quarter....................... 622.50 444.50 60.63 43.13 Second quarter...................... 649.00 506.00 59.31 46.98 Third quarter....................... 671.00 564.50 58.38 50.50 Fourth quarter...................... 646.50 517.50 57.31 45.13 2001: First quarter (through March 30).... 609.00 526.50 53.50 46.12 Month of September 2000............................ 671.00 594.50 57.31 52.06 October 2000.............................. 646.50 584.00 57.31 49.81 November 2000............................. 606.00 548.50 52.13 47.00 December 2000............................. 569.50 517.50 49.75 45.13 January 2001.............................. 595.00 526.50 52.63 46.69 February 2001............................. 609.00 561.50 53.50 48.05 March 2001 (through March 30)............. 602.00 542.50 52.86 46.12 </TABLE> - ---------- (a) An ADS is equivalent to six BP ordinary shares. Market prices for the BP ordinary shares on the LSE and in after-hours trading off the LSE, in each case while the New York Stock Exchange is open, and the market prices for ADSs on the New York Stock Exchange and other North American stock exchanges, are closely related due to arbitrage among the various markets, although differences may exist from time to time due to various factors including UK stamp duty reserve tax. Trading in ADSs began on the LSE on August 3, 1987. On March 30, 2001, 1,213,191,802 ADSs (equivalent to 7,279,150,812 BP ordinary shares or some 32.4% of the total) were outstanding and were held by approximately 187,000 ADR holders. Of these, about 185,000 had registered addresses in the USA at that date. On March 30, 2001 there were approximately 363,000 holders of record of BP ordinary shares. Of these holders, around 1,300 had registered addresses in the United States and held a total of some 3,983,000 BP ordinary shares. In addition, certain accounts of record with registered addresses other than in the United States hold BP ordinary shares, in whole or in part, beneficially for United States persons. 98
ITEM 10 -- ADDITIONAL INFORMATION MEMORANDUM AND ARTICLES OF ASSOCIATION The following summarizes certain provisions of BP's memorandum and articles of association and applicable English law. This summary is qualified in its entirety by reference to the UK Companies Act and BP's memorandum and articles of association. Information on where investors can obtain copies of the memorandum and articles of association is described under the heading 'Documents on Display' under this Item. Objects and Purposes BP is incorporated under the name BP Amoco p.l.c. and is registered in England and Wales with registered number 102498. Clause 4 of BP's memorandum of association provides that its objects include the acquisition of petroleum bearing lands; the carrying on of refining and dealing businesses in the petroleum, manufacturing, metallurgical or chemicals businesses; the purchase and operation of ships and all other vehicles and other conveyances; and the carrying on of any other businesses calculated to benefit BP. The memorandum grants BP a range of corporate capabilities to effect these objects. Directors The business and affairs of BP shall be managed by the directors. The articles of association place a general prohibition on a director voting in respect of any contract or arrangement in which he has a material interest other than by virtue of his interest in shares in the Company. However, in the absence of some other material interest not indicated below, a director is entitled to vote and to be counted in a quorum for the purpose of any vote relating to a resolution concerning the following matters: -- The giving of security or indemnity with respect to any money lent or obligation taken by the director at the request or benefit of the Company; -- Any proposal in which he is interested concerning the underwriting of Company securities or debentures; -- Any proposal concerning any other company in which he is interested, directly or indirectly (whether as an officer or shareholder or otherwise) provided that he and persons connected with him are not the holder or holders of one percent or more of the voting interest in the shares of such company; -- Proposals concerning the modification of certain retirement benefits schemes under which he may benefit and which has been approved by either the UK Board of Inland Revenue or by the shareholders; and -- Any proposal concerning the purchase or maintenance of any insurance policy under which he may benefit. The UK Companies Act requires a director of a company who is in any way interested in a contract or proposed contract with the company to declare the nature of his interest at a meeting of the directors of the company. The directors may exercise all the powers of the company to borrow money, except that the amount remaining undischarged of all moneys borrowed by the company shall not, without approval of the shareholders, exceed the amount paid up on the share capital plus the aggregate of the amount of the capital and revenue reserves of the company. Variation of the borrowing power of the board may only be effected by amending the articles of association. Remuneration of non-executive directors shall be determined in the aggregate by resolution of the shareholders. Remuneration of executive directors is determined by the Remuneration Committee. This committee is made up of non-executive directors only. Any director attaining the age of 70 shall retire at the next annual general meeting. There is no requirement of share ownership for a director's qualification. Dividend Rights; Other Rights to Share in Company Profits; Capital Calls If recommended by the directors of BP, BP shareholders may, by resolution, declare dividends but no such dividend may be declared in excess of the amount recommended by the directors. The directors may also pay interim dividends without obtaining shareholder approval. No dividend may be paid other than out of profits available for distribution, as determined under UK GAAP and the UK Companies Act. Dividends on BP ordinary shares are payable only after payment of dividends on BP preference shares. Any dividend unclaimed after a period of twelve years from the date of declaration of such dividend shall be forfeited and reverts to BP. 99
Apart from shareholders' rights to share in BP's profits by dividend (if any is declared), the articles of association provide that the directors may set aside. -- a special reserve fund out of the balance of profits each year to make up any deficit of cumulative dividend on the BP preference shares; and -- a general reserve out of the balance of profits each year, which shall be applicable for any purpose to which the profits of the company may properly be applied. This may include capitalization of such sum, pursuant to an ordinary shareholders' resolution, and distribution to shareholders as if it were distributed by way of a dividend on the ordinary shares or in paying up in full unissued ordinary shares for allotment and distribution as bonus shares. Any such sums so deposited may be distributed in accordance with the manner of distribution of dividends as described above. Holders of shares are not subject to calls on capital by the company, provided that the amounts required to be paid on issue have been paid off. All shares are fully paid. Voting Rights The articles of association of BP provide that voting on resolutions at a shareholders' meeting will be decided on a poll other than resolutions of a procedural nature, which may be decided on a show of hands. If voting is on a poll, every shareholder who is present in person or by proxy has one vote for every ordinary share held and two votes for every (pound)5 in nominal amount of BP preference shares held. If voting is on a show of hands, each shareholder who is present at the meeting in person or whose duly appointed proxy is present in person will have one vote, regardless of the number of shares held, unless a poll is requested. Shareholders do not have cumulative voting rights. Holders of record of ordinary shares may appoint a proxy, including a beneficial owner of those shares, to attend, speak and vote on their behalf at any shareholders' meeting. Record holders of BP ADSs also are entitled to attend, speak and vote at any shareholders' meeting of BP by the appointment by the approved depositary, Morgan Guaranty Trust Company, of them as proxies in respect of the ordinary shares represented by their ADSs. Each such proxy may also appoint a proxy. Alternatively, holders of ADSs are entitled to vote by supplying their voting instructions to the depositary, who will vote the ordinary shares represented by their ADSs in accordance with their instructions. Matters are transacted at shareholders' meetings by the proposing and passing of resolutions, of which there are three types: ordinary, special or extraordinary. An ordinary resolution requires the affirmative vote of a majority of the votes of those persons voting at a meeting at which there is a quorum. Special and extraordinary resolutions require the affirmative vote of not less than three-fourths of the persons voting at a meeting at which there is a quorum. Special resolutions require not less than 21 days notice, whereas ordinary and extraordinary resolutions require no formal notice period. Five persons constitute a quorum for all general meetings of shareholders. Liquidation Rights; Redemption Provisions In the event of a liquidation of BP, after payment of all liabilities and applicable deductions under UK laws and subject to the payment of secured creditors, the holders of BP preference shares would be entitled to the sum of (i) the capital paid up on such shares plus, (ii) accrued and unpaid dividends and (iii) a premium equal to the higher of (a) 10% of the capital paid up on the BP preference shares and (b) the excess of the average market price over par value of such shares on the London Stock Exchange during the previous six months. The remaining assets (if any) would be divided pro rata among the holders of BP ordinary shares. Without prejudice to any special rights previously conferred by the holders of any class of shares, BP may issue any share with such preferred, deferred or other special rights, or subject to such restrictions as the shareholders by resolution (or, in the absence of any such resolutions, by determination of the directors), and may issue shares which are to or may be redeemed. 100
Variation of Rights The rights attached to any class of shares may be varied with the consent in writing of holders of 75% of the shares of that class or upon the adoption of an extraordinary resolution passed at a separate meeting of the holders of the shares of that class. At every such separate meeting, all of the provisions of the articles of association relating to proceedings at a general meeting apply, except that the quorum with respect to meeting to change the rights attached to the preference shares is 10% or more of the shares of that class, and the quorum to change the rights attached to the ordinary shares is one third or more of the shares of that class. Shareholders' Meetings and Notices Shareholders must provide BP with an address in the UK in order to be entitled to receive notice of shareholders' meetings. In certain circumstances, BP may give notices to shareholders by advertisement in UK newspapers. Holders of BP ADSs are entitled to receive notices under the terms of the deposit agreement relating to BP ADSs. Under the articles of association, the annual general meeting of shareholders will be held within 15 months after the preceding annual general meeting and at a time and place determined by the directors within the United Kingdom. Limitations on Voting and Shareholding There are no limitations imposed by English law or BP's memorandum or articles of association on the right of non-residents or foreign persons to hold or vote the Company's ordinary shares or ADSs, other than limitations that would generally apply to all of the shareholders. Disclosure of Interests in Shares The UK Companies Act gives BP the power to require persons whom it believes to have, or to have acquired in the previous three years, an interest in its voting shares to disclose certain information with respect to those interests. Failure to supply the information required may lead to disenfranchisement of the relevant shares and a prohibition on their transfer and receipt of dividends and other payments in respect of those shares. In this context the term 'interest' is widely defined and will generally include an interest of any kind whatsoever in voting shares, including any interest of a holder of BP ADSs. MATERIAL CONTRACTS The following contract (not being contracts entered into in the ordinary course of business) has been entered into by members of the Group since January 1,1999 that is material: A merger agreement under Delaware law dated March 31, 1999 and amended as of July 12, 1999 and again as of March 27, 2000 pursuant to which Prairie Holdings (a wholly-owned subsidiary of BP) was to be merged with and into Atlantic Richfield Company (ARCO) and ARCO was to become a wholly-owned subsidiary of BP. Under the terms of the merger, each ARCO shareholder was entitled to receive 9.84 BP ordinary shares (in the form of BP ADSs) for each ARCO share. The merger agreement contained certain customary representations and warranties by ARCO and BP with respect to themselves and their respective subsidiaries, regarding, among other things, due organization, good standing and qualification, capital structure, corporate authority and compliance with corporate governance documents, government filings, reports and financial statements, litigation and liabilities, absence of certain changes, employee benefits, environmental matters and tax matters. The merger was declared effective on April 18, 2001, at which time 3,186,006,476 BP ordinary shares were issued as consideration in the merger. EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS There are currently no UK foreign exchange controls or restrictions on remittances of dividends on the BP ordinary shares or on the conduct of the Company's operations. There are no limitations, either under the laws of the UK or under the articles of association of BP Amoco p.l.c., restricting the right of non-resident or foreign owners to hold or vote BP ordinary or preference shares in the Company. 101
TAXATION The following summary of the principal UK and certain US tax consequences of ownership of ADSs or BP ordinary shares is based in part on representations of Morgan Guaranty Trust Company of New York as Depositary for the ADRs evidencing the ADSs and assumes that each obligation in the deposit agreement among the Company, the Depositary and the holders from time to time of ADRs and any related agreement will be performed in accordance with its terms. Beneficial owners of ADSs who are resident in the USA are treated as the owners of the underlying BP ordinary shares for the purposes of the income tax convention between the USA and the UK (the Convention) and for the purposes of the US Internal Revenue Code of 1986, as amended (the Code). Unless otherwise stated, references to 'shareholders' or 'shareholder' below are to persons who are the beneficial owners of the underlying BP ordinary shares. It should be noted that the UK Inland Revenue is currently negotiating with the US Internal Revenue Service about updating and revising the Convention. For purposes of this discussion, a US Holder is a beneficial owner of the Company's shares who for the purposes of the Convention is not a US corporation owning directly or indirectly 10% or more of the Company's voting stock, and who is a resident of the USA and is not a resident of the UK. UK Taxation of Dividends The tax credit for an individual shareholder resident in the UK is reduced to 1/9 of the amount of the net dividend (or 10% of the net dividend plus the tax credit). This tax credit continues to be available to set against the individual's tax liability on the dividend, but is no longer refundable to the individual. For purposes of this section, with respect to any dividend paid by the Company, Refund means an amount equal to the tax credit available to individual shareholders resident in the UK in respect of such dividend, less a withholding tax equal to 15% of the aggregate of such tax credit and such dividend. In the case of a US Holder as defined above that is eligible for the benefits under the Convention (an Eligible US Holder) no actual Refund is available under the Convention since the amount of the withholding tax (at 15%) exceeds the 10% tax credit available to individual shareholders resident in the UK. For example, a dividend of $8.00 will result in a net receipt after UK tax but before US tax of $8.00 i.e. the withholding tax does not reduce the dividend below the net dividend of $8.00. Dividends (including amounts in respect of the tax credit and any amounts withheld) must be included in gross income by a shareholder subject to US taxation and will generally be treated as foreign source 'passive income' or, in the case of certain US Holders, 'financial services income' for foreign tax credit limitations purposes. Such dividends will generally not be eligible for the dividends received deduction allowed to US corporations. The IRS has recently confirmed, that, in the case of Eligible US Holders, subject to certain limitations, the UK withholding tax as determined by the Convention (i.e. an amount equal to 1/9 of the cash dividend) will be treated as a foreign income tax that is eligible for credit against the US Holders' federal income tax. To qualify for such credit, Eligible US Holders must make an election on Form 8833 (a Treaty-Based Return Position Disclosure), which must be filed with their tax return, in addition to any other filings that may be required. At the end of the calendar year during which the dividends are paid, US Holders will receive a Form 1099 confirming the amount of dividends received. Share Dividend Choice for BP ADR Holders ADR holders electing to receive ADSs instead of a cash dividend (see Item 3 -- Key Information -- Dividends) will not be entitled to any Refund from the UK Inland Revenue, nor will the 15% withholding tax apply, with respect to such dividends. For US tax purposes the receipt of additional ADSs will be treated as a dividend distribution. An ADR holder who is subject to US taxation will generally be treated as having received gross income equal to the fair market value of the ADSs (or fraction thereof) on the date of the share distribution in London (with no reduction for the stamp duty reserve tax referred to below). The US resident ADR holder will receive a tax basis in the ADSs equal to such fair market value. Corporations will not be entitled to a dividends received deduction on receipt of a share dividend. 102
UK Taxation of Capital Gains A US Holder will be liable to UK tax on capital gains realized on the sale or other disposition of BP ordinary shares only if the US Holder is resident (or, in the case of an individual, ordinarily resident) for UK tax purposes in the UK or if he carries on a trade, profession or vocation in the UK through a permanent establishment and the BP ordinary shares are (i) used for the purposes of the trade, profession or vocation, or (ii) used, held or acquired for the purposes of the permanent establishment. The liability to UK capital gains tax for a US Holder of ADRs is the same as that for a US Holder of BP ordinary shares, except that a US Holder of ADRs who is resident but not domiciled in the UK will not be taxed on gains realized on the sale or other disposition of ADSs if the proceeds are not remitted to the UK. UK Inheritance Tax UK capital transfer tax was restructured and renamed 'inheritance tax' in 1986. The US-UK double taxation convention relating to estate and gift taxes (the Estate Tax Convention) applies to inheritance tax. ADRs held by an individual who is domiciled for the purposes of the Estate Tax Convention in the USA and is not for the purposes of the Estate Tax Convention a national of the UK will not be subject to inheritance tax on death or on transfer during the individual's lifetime unless, among other things, the ADSs are part of the business property of a permanent establishment situated in the UK or pertain to a fixed base situated in the UK used for the performance of independent personal services. In the exceptional case where ADSs are subject both to inheritance tax and to US Federal gift or estate tax, the Estate Tax Convention generally provides for tax paid in the UK to be credited against tax payable in the USA or for tax paid in the USA to be credited against tax payable in the UK based on priority rules set forth in the Estate Tax Convention. UK Stamp Duty and Stamp Duty Reserve Tax The statements below relate to what is understood to be the current practice of the UK Inland Revenue under existing law. Provided that the instrument of transfer is not executed in the UK and remains at all times outside the UK, and the transfer does not relate to any matter or thing done or to be done in the UK, no UK stamp duty is payable on the acquisition or transfer of ADSs. Neither will an agreement to transfer ADSs in the form of ADRs give rise to a liability to stamp duty reserve tax. Purchases of BP ordinary shares, as opposed to ADSs, through the CREST system of paperless share transfers will be subject to stamp duty reserve tax at a rate of 0.5%. The charge will arise as soon as there is an agreement for the transfer of the shares (or, in the case of a conditional agreement, when the condition is fulfilled). The stamp duty reserve tax will apply to agreements to transfer BP ordinary shares even if the agreement is made outside the UK between two non-residents. Purchases of BP ordinary shares outside the CREST system are subject either to stamp duty at a rate of 50 pence per (pound)100 (or part), or stamp duty reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are generally the liability of the purchaser. A subsequent transfer of BP ordinary shares to the Depositary's nominee will give rise to further stamp duty at the rate of (pound)1.50 per (pound)100 (or part) or stamp duty reserve tax at the rate of 1.5% of the value of the BP ordinary shares at the time of the transfer. A transfer of the underlying BP ordinary shares to an ADR holder upon cancellation of the ADSs without transfer of beneficial ownership will give rise to UK stamp duty at the rate of (pound)5 per transfer. An ADR holder electing to receive ADSs instead of a cash dividend will be responsible for the stamp duty reserve tax due on issue of shares to the Depositary's nominee and calculated at the rate of 1.5% on the issue price of the shares. Current UK Inland Revenue practice is to calculate the issue price by reference to the total cash receipt (i.e. cash dividend plus the Refund if any) to which a US Holder would have been entitled had the election to receive ADSs instead of a cash dividend not been made. ADR holders electing to receive ADSs instead of the cash dividend authorize the Depositary to sell sufficient shares to cover this liability. DOCUMENTS ON DISPLAY It is possible to read and copy documents referred to in this annual report on Form 20-F that have been filed with the SEC at the SEC's public reference room located at 450 Fifth Street, NW, Washington, DC 20549 and at the SEC's other public reference rooms in New York City and Chicago. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and their copy charges. The SEC filings are also available to the public from commercial document retrieval services and, for most recent BP periodic filings only, at the Internet world wide web site maintained by the SEC at www.sec.gov. 103
ITEM 11 -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK BP is exposed to a number of different market risks arising from the Group's normal business activities. Market risk is the possibility that changes in currency exchange rates, interest rates or oil and natural gas prices will adversely affect the value of the Group's financial assets, liabilities or expected future cash flows. The Group has developed policies aimed at managing the volatility inherent in certain of these natural business exposures and in accordance with these policies the Group enters into various transactions using derivative financial and commodity instruments (derivatives). Derivatives are contracts whose value is derived from one or more underlying financial instruments, indices or prices which are defined in the contract. We also trade derivatives in conjunction with these risk management activities. In market risk management and in trading, only well-understood, conventional derivative instruments are used. These include futures and options traded on regulated exchanges, and 'over-the-counter' swaps, options and forward contracts. Where derivatives constitute a hedge, the Group's exposure to market risk created by the derivative is offset by the opposite exposure arising from the asset, liability or transaction being hedged. By contrast, where derivatives are held for trading purposes, changes in market risk factors give rise to realized and unrealized gains and losses, which are recognized in the current period. All material derivatives activity, whether for risk management or trading, is carried out by specialist teams which have 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. A Group Trading Risk Management Committee was established in 2000, composed of senior executives whose reponsibilities include oversight of the quality of internal control in the Group's trading divisions. Independent control functions monitor compliance with BP's derivative management policies. The control framework includes prescribed trading limits that are reviewed regularly by senior management, daily monitoring of risk exposure, marking trading exposures to market and reviewing open positions to assess BP's exposure in potentially adverse situations. Counterparty credit validation, independent of the dealers, is undertaken before contractual commitment. Further information about BP's use of derivatives, their characteristics, and the accounting treatment thereof is given in Item 18 -- Financial Statements - -- Note 1 and Note 28. The Group's accounting policies under UK GAAP do not satisfy the criteria for hedge accounting under Statement of Financial Accounting Standards No. 133 'Accounting for Derivative Instruments and Hedging Activities'. The Group does not intend to modify its practice under UK GAAP. See Item 18 -- Financial Statements -- Note 43 for further information. Risk Management Foreign Currency Exchange Rate Risk Fluctuations in exchange rates can have significant effects on BP's operating results. The effects of most exchange rate fluctuations are subsumed within business operating results through changing cost-competitiveness, lags in market adjustment to movements in rates, and conversion differences accounted on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the Group's reported results. The main underlying economic currency of the Group's cash flows is the US dollar. This is because BP's major product, oil, is priced internationally in US dollars. BP's foreign exchange management policy is to minimize economic and material transactional exposures from currency movements against the US dollar. The Group co-ordinates the handling of foreign exchange risks centrally, by netting off naturally occurring opposite exposures wherever possible, to reduce the risk, and then dealing with any material residual foreign exchange risks. Significant residual non-US dollar exposures are managed using a range of derivatives. The most significant of such exposures are the sterling-based capital leases, that part of the quarterly dividend which is paid in sterling, the sterling cash flow requirements for UK Corporation Tax, and the capital expenditure and operational requirements of Exploration and Production, mainly in the UK. In addition, most of the Group's borrowings are in US dollars, are hedged with respect to the US dollar, or are swapped into dollars where this achieves a lower cost of financing. At December 31, 2000, the total of foreign currency borrowings not swapped into US dollars amounted to $741 million. The principal elements of this are $449 million of borrowings in sterling and $115 million of borrowings in Malaysian ringgits. 104
The following table provides information about the Group's foreign currency derivative financial instruments. These include foreign currency forward exchange agreements (forwards) that are sensitive to changes in the sterling/US dollar, euro/US dollar and Norwegian krone/US dollar exchange rates. Where foreign currency denominated borrowings are swapped into dollars using forwards or currency interest rate swaps such that currency risk is completely eliminated, neither the borrowing nor the derivative are included in the table. The table presents the notional amounts and weighted average contractual exchange rates by contractual maturity dates and exclude forwards that have offsetting positions. Only significant forward positions are included in the tables. The notional amounts of forwards are translated into US dollars at the exchange rate included in the contract at inception. The majority of the sterling contracts consist of forwards relating to sterling-based capital leases which effectively convert the lease obligation from sterling into US dollars. The remaining contracts relate to sterling requirements for UK tax payments, which were covered at December 31, 1999 by cylinders, and UK dividend payments and net operational expenditures which were greater at December 31, 2000 than at December 31, 1999. The euro forward contracts relate mainly to payments for capital expenditure. The Norwegian krone forward contracts relate to the Group's Norwegian tax payments over the next year. The fair value represents an estimate of the gain or loss which would be realized if the contracts were settled at the balance sheet date. The fair values for the foreign exchange contracts in the table below are based on market prices of comparable instruments (forwards). These derivative contracts constitute a hedge; any change in the fair value or expected cash flows is offset by an opposite change in the market value or expected cash flows of the asset, liability or transaction being hedged. <TABLE> <CAPTION> Notional amount by expected maturity date --------------------------------------------------------------------- Fair value asset/ 2001 2002 2003 2004 Total (liability) ----- ----- ----- ---------- ----- ----------- ($ million) <S> <C> <C> <C> <C> <C> <C> At December 31, 2000 Forwards Receive sterling/pay US dollars Contract amount...................... 3,299 -- -- -- 3,299 (30) Weighted average contractual exchange rate...................... 1.52 Receive euro/pay US dollars Contract amount...................... 663 45 23 13 744 (16) Weighted average contractual exchange rate...................... 1.01 Receive Norwegian krone/pay US dollars Contract amount...................... 199 -- -- -- 199 6 Weighted average contractual exchange rate...................... 9.19 At December 31, 1999 Forwards Receive sterling/pay US dollars Contract amount...................... 1,674 -- -- -- 1,674 (26) Weighted average contractual exchange rate...................... 1.64 Cylinders Receive sterling/pay US dollars Purchased call Contract amount...................... 286 -- -- -- 286 2 Weighted average strike rate......... 1.71 Written put Contract amount...................... 286 -- -- -- 286 (4) Weighted average strike rate......... 1.57 </TABLE> 105
Interest Rate Risk BP is exposed to interest rate risk on short- and long-term floating-rate instruments and as a result of the refinancing of fixed-rate finance debt. Consequently, as well as managing the currency and the maturity of debt, the Group manages interest costs through the balance between generally lower-cost floating rate debt, which has inherently higher risk, and generally more expensive but lower-risk, fixed-rate debt. The Group is exposed predominantly to US dollar LIBOR interest rates as borrowings are mainly denominated in, or swapped into, US dollars. The BP Group uses derivatives to achieve the required mix between fixed and floating rate debt. During 2000, debt policy was to keep floating rate debt below an upper limit of 65% of total net debt. Actual floating rate debt for the year was in the range of 19-54%. The low percentage in mid-year reflected the temporary high cash balance following the disposal of ARCO's Alaskan business. The overall level of debt at December 31, 2000 is higher than at December 31, 1999 mainly as a result of the debt assumed on the ARCO and Burmah Castrol acquisitions. The following table shows, by major currency, the Group's borrowings at December 31, 2000 and the weighted average interest rates achieved at those dates through a combination of borrowings and other interest rate sensitive instruments entered into to manage interest rate exposure. <TABLE> <CAPTION> Fixed rate debt Floating rate debt ---------------------------------------- -------------------- Weighted Weighted Weighted average average time average interest for which interest rate rate is fixed Amount rate Amount Total -------- ------------- -------- -------- -------- -------- (%) (Years) ($ million) (%) ($ million) ($ million) <S> <C> <C> <C> <C> <C> <C> At December 31, 2000 US dollars..................... 7 9 10,199 6 8,326 18,525 Sterling...................... -- -- -- 6 449 449 Other currencies.............. 8 30 45 10 247 292 ------- ------- ------- Total loans 10,244 9,022 19,266 ======= ======= ======= At December 31, 1999 US dollars..................... 7 9 6,529 6 5,915 12,444 Sterling...................... -- -- -- 6 49 49 Other currencies.............. 8 31 46 6 180 226 ------- ------- ------- Total loans 6,575 6,144 12,719 ======= ======= ======= </TABLE> The Group's earnings are sensitive to changes in interest rates over the forthcoming year as a result of the floating rate instruments included in the Group's finance debt at December 31, 2000. These include the effect of interest rate and currency swaps and forwards utilized to manage interest rate risk. If the interest rates applicable to floating rate instruments were to have increased by 1% on January 1, 2001, the Group's 2001 earnings before taxes would decrease by approximately $110 million. This assumes that the amount and mix of fixed and floating rate debt, including capital leases, remains unchanged from that in place at December 31, 2000 and that the change in interest rates is effective from the beginning of the year. Where the interest rate applicable to an instrument is reset during a quarter it is assumed that this occurs at the beginning of the quarter and remains unchanged for the rest of the year. In reality, the fixed/floating rate mix will fluctuate over the year and interest rates will change continually. Furthermore the effect on earnings shown by this analysis does not consider the effect of an overall reduction in economic activity which could accompany such an increase in interest rates. 106
Oil Price Risk The Group's risk management policy with respect to oil price risk is to manage only those exposures associated with the immediate operational programme for certain of its equity share of production and certain of its refinery and marketing activities. To this end, BP's oil trading division uses the full range of conventional oil price-related financial and commodity derivatives available in the oil markets. The derivative instruments used for hedging purposes do not expose the Group 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. The values at risk in respect of derivatives held for oil price risk management purposes are shown in isolation in the table below. The items being hedged are not included in the values at risk. The value at risk model used is that discussed under Trading below, except that value at risk in respect of oil price risk management does not take into account physical crude oil or refined product positions held by the Group. Thus the value at risk calculation for oil price exposure includes derivative financial instruments such as exchange-traded futures and options, swap agreements and over-the-counter options and derivative commodity instruments (commodity contracts that permit settlement either by delivery of the underlying commodity or in cash) such as forward contracts. The values at risk represent the potential gain or loss in fair values over a 24-hour period with a 99.7% confidence level. The following table shows values at risk for oil price risk management activities. <TABLE> <CAPTION> High Low Average December 31 ------ ------ ------- ----------- ($ million) <S> <C> <C> <C> <C> 2000 Oil price contracts......... 18 11 15 11 1999 Oil price contracts......... 5 3 3 5 </TABLE> Natural Gas Price Risk BP's general policy with respect to natural gas price risk is to manage only a portion of its exposure to price fluctuations. Natural gas swaps, options and futures are used to convert specific sales and purchases contracts from fixed prices to market prices. Swaps are also used to hedge exposure to price differentials between locations. We also use derivatives to fix prices which are favourable with respect to our forecasts of future prices. The table below provides information about the Group's material swaps contracts that are sensitive to changes in natural gas prices. Contract amount represents the notional amount of the contract. Fair value represents an estimate of the gain or loss which would be realized if the contracts were settled at the balance sheet date. Weighted average price represents the year-end forward price for futures, the fixed price and the year-end forward price related to the settlement month for swaps; and the weighted average strike price for options. At December 31, 2000, in addition to the swaps contracts shown in the table there were options contracts with aggregate notional amounts of $7 million ($7 million at December 31, 1999) and terms of up to one year. 107
<TABLE> <CAPTION> Weighted Fair value average price Contract ---------------------- ----------------- Quantity amount Asset Liability Receive Pay -------- ------ ----- --------- ------- ---- (Btu trillion)(a) ($ million) ($ million) ($ per mmBtu)(b) <S> <C> <C> <C> <C> <C> <C> At December 31, 2000 Maturing in 2001 Swaps Receive variable/pay fixed..... 30 129 72 (1) 4.30 6.80 Receive fixed/pay variable..... 12 67 1 (28) 8.18 5.80 Receive and pay variable....... 265 1,932 46 (72) 7.28 7.18 Maturing in 2002 Swaps Receive variable/pay fixed..... 13 54 12 (1) 3.90 4.30 Receive fixed/pay variable..... 1 2 -- (1) 3.47 3.20 Receive and pay variable....... 40 198 2 (11) 4.87 4.64 Maturing in 2003 Swaps Receive variable/pay fixed..... 2 7 -- -- 4.00 3.87 Receive and pay variable....... 15 56 -- -- 3.86 3.87 Maturing in 2004 Swaps Receive variable/pay fixed..... 2 7 -- -- 3.91 4.01 Receive and pay variable....... 2 7 -- -- 3.84 3.83 Maturing in 2005 Swaps Receive variable/pay fixed..... 2 7 -- -- 3.91 4.01 Receive and pay variable....... 2 7 -- -- 3.86 3.83 Maturing beyond 2005 Swaps Receive variable/pay fixed..... 5 19 -- -- 3.99 4.01 Receive and pay variable....... 5 19 -- -- 3.87 3.83 At December 31, 1999 Maturing in 2000 Swaps Receive variable/pay fixed..... 78 201 3 (10) 2.47 2.58 Receive fixed/pay variable..... 55 138 6 (2) 2.51 2.43 Receive and pay variable....... 1,474 3,350 36 (32) 2.28 2.27 Maturing in 2001 Swaps Receive variable/pay fixed..... 14 38 1 (1) 2.63 2.68 Receive fixed/pay variable..... 6 14 -- -- 2.51 2.44 Receive and pay variable....... 252 604 9 (7) 2.41 2.40 </TABLE> - --------------- (a) British thermal units (Btu) (b) Million british thermal units (mmBtu) 108
Trading In conjunction with the risk management activities discussed above, BP also trades interest rate and foreign currency exchange rate derivatives. The Group controls the scale of the trading exposures by using a value at risk model with a maximum value at risk limit authorized by the board. In addition to the risk management activities related to equity crude disposal, refinery supply and marketing, BP's oil trading division undertakes trading in the full range of conventional derivative financial and commodity instruments and physical cargoes available in the oil markets. The Group also uses financial and commodity derivatives to manage certain of its exposures to price fluctuations on natural gas transactions. These activities are monitored and measured separately from the risk management activity and are subject to maximum value at risk limits authorized by the board. The Group intends to increase the volume of its natural gas trading activity in 2001. The Group measures its market risk exposure, i.e. potential gain or loss in fair values, on its trading activity using a value at risk technique. This technique is based on a variance/covariance model and makes 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 which is 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 Group 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 model takes account of derivative financial instruments such as interest rate forward and futures contracts, swap agreements, options and swaptions; foreign exchange forward and futures contracts, swap agreements and options; and oil and natural gas price futures, swap agreements and options. Financial assets and liabilities and physical crude oil and refined products that are treated as trading positions are also included in these calculations. The value at risk calculation for oil 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. The following table shows values at risk for trading activities. <TABLE> <CAPTION> High Low Average December 31 ----- ----- ------- ----------- ($ million) <S> <C> <C> <C> <C> 2000 Interest rate trading....... 2 -- 1 -- Foreign exchange trading.... 15 -- 1 1 Oil price trading........... 23 4 13 13 Natural gas price trading... 16 1 6 13 1999 Interest rate trading....... 1 -- 1 -- Foreign exchange trading.... 13 -- 3 1 Oil price trading........... 15 5 9 10 </TABLE> ITEM 12 -- DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES Not applicable. 109
PART II ITEM 13 -- DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES None. ITEM 14-- MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS None. 110
PART III ITEM 17 -- FINANCIAL STATEMENTS Not applicable. ITEM 18 -- FINANCIAL STATEMENTS The following financial statements, together with the reports of the Independent Auditors thereon, are filed as part of this annual report: <TABLE> <CAPTION> <S> <C> Page Report of Independent Auditors and Consent of Independent Auditors....................... F-1 Consolidated Statement of Income for the Years Ended December 31, 2000, 1999, and 1998... F-2 Consolidated Balance Sheet at December 31, 2000 and 1999................................. F-3 Consolidated Statement of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998................................................. F-4 Statement of Total Recognized Gains and Losses for the Years Ended December 31, 2000, 1999 and 1998................................................. F-4 Statement of Changes in BP Shareholders' Interest for the Years Ended December 31, 2000, 1999 and 1998....................................... F-5 Notes to Financial Statements............................................................ F-7 Supplementary Oil and Gas Information (Unaudited)........................................ F-99 Schedule for the Years Ended December 31, 2000, 1999 and 1998 Schedule II Valuation and Qualifying Accounts.......................................... S-1 ITEM 19 -- EXHIBITS The following documents are filed as part of this annual report: Exhibit 1 Memorandum and Articles of Association of BP Amoco p.l.c. Exhibit 4.1 The BP Amoco Executive Directors' Long Term Incentive Plan Exhibit 4.2 Directors' Service Contracts Exhibit 7 Computation of Ratio of Earnings to Fixed Charges (Unaudited) Exhibit 8 Subsidiaries </TABLE> The total amount of long-term debt securities of the Registrant and its subsidiaries authorized under any one instrument does not exceed 10% of the total assets of BP Amoco p.l.c. and its subsidiaries on a consolidated basis. The Company agrees to furnish copies of any or all such instruments to the Securities and Exchange Commission upon request. 111
SIGNATURES The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf. BP AMOCO p.l.c. (Registrant) /s/ Judith C. Hanratty (Secretary) Dated: April 3, 2001 112
REPORT OF INDEPENDENT AUDITORS To: The Board of Directors BP Amoco p.l.c. We have audited the accompanying consolidated balance sheets of BP Amoco p.l.c. as of December 31, 2000 and 1999, and the related consolidated statements of income, changes in BP shareholders' interest, total recognized gains and losses, and cash flows for each of the three years in the period ended December 31, 2000. Our audits also included the financial statement schedule listed in the Index at Item 18. 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 auditing standards generally accepted in the United Kingdom and United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of BP Amoco p.l.c. at December 31, 2000 and 1999, and the consolidated results of its operations and its consolidated cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United Kingdom which differ in certain respects from those followed in the United States (see Note 43 of Notes to Financial Statements). 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. /s/ ERNST&YOUNG London, England Ernst & Young February 13, 2001 - -------------------------------------------------------------------------------- CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference of our report dated February 13, 2001, with respect to the consolidated financial statements of BP Amoco p.l.c. included in this Annual Report (Form 20-F) for the year ended December 31, 2000 in the following Registration Statements: Registration Statement on Form F-3 (File No. 333-9790) of BP Amoco p.l.c.; Registration Statements on Form F-3 (File Nos. 33-39075 and 33-20338) of BP America Inc. and BP Amoco p.l.c.; Registration Statement on Form F-3 (File No. 33-29102) of The Standard Oil Company and BP Amoco p.l.c.; and Registration Statements on Form S-8 (File Nos. 33-21868, 333-9020, 333-9798, 333-79399 and 333-34968) of BP Amoco p.l.c. /s/ ERNST&YOUNG London, England Ernst & Young March xx, 2001 F - 1
CONSOLIDATED STATEMENT OF INCOME <TABLE> <CAPTION> Years ended December 31, -------------------------- Note 2000 1999 1998 ---- -------------------------------- ----- ----- Continuing operations -------------------------------- Acquisitions Total ------------ ----- ($ million, except per share amounts) <S> <C> <C> <C> <C> <C> <C> Turnover.................................... 144,898 16,928 161,826 101,180 83,732 Less: Joint ventures........................ 13,339 425 13,764 17,614 15,428 ------ ------ ------ ------ ------ Group turnover.............................. 2 131,559 16,503 148,062 83,566 68,304 Replacement cost of sales................... 107,155 14,361 121,516 68,615 56,270 Production taxes............................ 3 1,936 125 2,061 1,017 604 ------ ------ ------ ------ ------ Gross profit................................ 22,468 2,017 24,485 13,934 11,430 Distribution and administration expenses.... 4 6,870 1,665 8,535 6,064 6,044 Exploration expense......................... 460 139 599 548 921 ------ ------ ------ ------ ------ 15,138 213 15,351 7,322 4,465 Other income................................ 5 531 274 805 414 709 ------ ------ ------ ------ ------ Group replacement cost operating profit..... 15,669 487 16,156 7,736 5,174 Share of profits of joint ventures.......... 688 120 808 555 825 Share of profits of associated undertakings. 773 19 792 603 522 ------ ------ ------ ------ ------ Total replacement cost operating profit..... 17,130 626 17,756 8,894 6,521 Profit (loss) on sale of businesses......... 6 132 -- 132 363 395 Profit (loss) on sale of fixed assets....... 6 88 -- 88 (700) 653 Restructuring costs......................... 6 -- -- -- (1,943) -- Merger expenses............................. 6 -- -- -- -- (198) ------ ------ ------ ------ ------ Replacement cost profit before interest and tax 17,350 626 17,976 6,614 7,371 Inventory holding gains (losses)............ 807 (79) 728 1,728 (1,391) ------ ------ ------ ------ ------ Historical cost profit before interest and tax 18,157 547 18,704 8,342 5,980 Interest expense............................ 7 ------ ------ 1,770 1,316 1,177 ------ ------ ------ Profit before taxation...................... 16,934 7,026 4,803 Taxation.................................... 9 4,972 1,880 1,520 ------ ------ ------ Profit after taxation....................... 11,962 5,146 3,283 Minority shareholders' interest............. 92 138 63 ------ ------ ------ Profit for the year*........................ 11,870 5,008 3,220 Dividend requirements on preference shares*. 2 2 1 ------ ------ ------ Profit for the year applicable to ordinary shares* 11,868 5,006 3,219 ====== ====== ====== Profit per ordinary share - cents Basic ...................................... 11 54.85 25.82 16.77 Diluted..................................... 11 54.48 25.68 16.70 ====== ====== ====== Dividends per ordinary share - cents........ 10 20.5 20.0 19.8 ====== ====== ====== Average number outstanding of 25 cents ordinary shares (in millions)............................. 21,638 19,386 19,192 ====== ====== ====== </TABLE> - ---------- * A summary of the adjustments to profit for the year of the Group which would be required if generally accepted accounting principles in the United States had been applied instead of those generally accepted in the United Kingdom is given in Note 43. The Notes to Financial Statements are an integral part of this Statement. F - 2
CONSOLIDATED BALANCE SHEET <TABLE> <CAPTION> December 31, --------------------------------- Note 2000 1999 ------ --------------- ---------------- ($ million) <S> <C> <C> <C> <C> <C> Fixed assets Intangible assets................. 19 16,893 3,344 Tangible assets................... 20 75,173 52,631 Investments Joint ventures Gross assets................... 3,641 9,948 Gross liabilities.............. 757 4,744 ------ ------ Net investment................. 21 2,884 5,204 Associated undertakings.......... 21 5,455 4,334 Other............................ 21 3,414 571 ------ ------ 11,753 10,109 ------ ------ Total fixed assets.................. 103,819 66,084 Current assets Business held for resale.......... 636 -- Inventories....................... 22 9,234 5,124 Trade receivables................. 23 17,813 9,417 Other receivables falling due Within one year.................. 23 5,995 3,930 After more than one year......... 23 4,610 3,455 Investments....................... 24 661 220 Cash at bank and in hand.......... 1,170 1,331 ------ ------ 40,119 23,477 ------ ------ Current liabilities -- falling due within one year Finance debt...................... 25 6,418 4,900 Trade payables.................... 26 14,363 8,203 Other accounts payable and accrued liabilities............. 26 16,366 10,172 ------ ------ 37,147 23,275 ------ ------ Net current assets ................. 2,972 202 ------ ------ Total assets less current liabilities 106,791 66,286 Noncurrent liabilities Finance debt...................... 25 14,772 9,644 Accounts payable and accrued liabilities 26 5,223 2,245 Provisions for liabilities and charges Deferred taxation................. 9 1,822 1,783 Other............................. 27 10,973 8,272 ------ ------ 32,790 21,944 ------ ------ Net assets.......................... 74,001 44,342 Minority shareholders' interest..... 585 1,061 ------ ------ BP shareholders' interest*.......... 73,416 43,281 ====== ====== Represented by: Capital shares Preference........................ 21 21 Ordinary.......................... 5,632 4,871 Paid in surplus..................... 29 3,770 3,684 Merger reserve...................... 29 26,869 697 Other reserves...................... 29 456 -- Retained earnings................... 29/30 36,668 34,008 ------ ------ 73,416 43,281 ====== ====== </TABLE> - ---------- * A summary of the adjustments to BP shareholders' interest which would be required if generally accepted accounting principles in the United States had been applied instead of those generally accepted in the United Kingdom is given in Note 43. The Notes to Financial Statements are an integral part of this Balance Sheet. F - 3
CONSOLIDATED STATEMENT OF CASH FLOWS <TABLE> <CAPTION> Years ended December 31, ------------------------ Note 2000 1999 1998 ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Net cash inflow from operating activities............ 31 20,416 10,290 9,586 ------ ------ ------ Dividends from joint ventures........................ 645 949 544 ------ ------ ------ Dividends from associated undertakings............... 394 219 422 ------ ------ ------ Servicing of finance and returns on investments Interest received.................................... 444 179 223 Interest paid........................................ (1,354) (1,065) (961) Dividends received................................... 42 34 43 Dividends paid to minority shareholders.............. (24) (151) (130) ------ ------ ------ Net cash outflow from servicing of finance and returns on investments............................. (892) (1,003) (825) ------ ------ ------ Taxation UK corporation tax................................... (869) (559) (391) Overseas tax......................................... (5,329) (701) (1,314) ------ ------ ------ Tax paid............................................. (6,198) (1,260) (1,705) ------ ------ ------ Capital expenditure and financial investment Payments for fixed assets............................ (10,037) (6,457) (8,431) Purchase of shares for employee share schemes........ (64) (77) (254) Proceeds from the sale of fixed assets............... 18 3,029 1,149 1,387 ------ ------ ------ Net cash outflow for capital expenditure and financial investment........................... (7,072) (5,385) (7,298) ------ ------ ------ Acquisitions and disposals Investments in associated undertakings............... (985) (197) (396) Acquisitions......................................... 17 (6,265) (102) (314) Net investment in joint ventures..................... (218) (750) 708 Proceeds from the sale of businesses................. 18 8,333 1,292 780 ------ ------ ------ Net cash inflow for acquisitions and disposals....... 865 243 778 ------ ------ ------ Equity dividends paid................................ (4,415) (4,135) (2,408) ------ ------ ------ Net cash inflow (outflow)............................ 3,743 (82) (906) ====== ====== ====== Financing............................................ 31 3,413 (954) (377) Management of liquid resources....................... 31 452 (93) (596) Increase (decrease) in cash.......................... 31 (122) 965 67 ------ ------ ------ 3,743 (82) (906) ====== ====== ====== </TABLE> - -------------------------------------------------------------------------------- STATEMENT OF TOTAL RECOGNIZED GAINS AND LOSSES <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Profit for the year.................................. 11,870 5,008 3,220 Currency translation differences..................... (2,508) (921) 55 ------ ------ ------ Total recognized gains and losses relating to the year 9,362 4,087 3,275 Prior year adjustment-- change in accounting policy.. -- 715 -- ------ ------ ------ Total recognized gains and losses.................... 9,362 4,802 3,275 ====== ====== ====== </TABLE> - --------------- For a cash flow statement and a statement of comprehensive income prepared on the basis of US GAAP see Note 43 -- US generally accepted accounting principles. - -------------------------------------------------------------------------------- The Notes to Financial Statements are an integral part of these Statements. F - 4
STATEMENT OF CHANGES IN BP SHAREHOLDERS' INTEREST During 2000 the parent Company's authorized ordinary share capital was increased from 24 billion to 36 billion shares of 25 cents each amounting to $9 billion. In addition the Company has authorised preference share capital of 12,750,000 shares of (pound)1 each ($21 million). At the date of completion of the acquisition of ARCO, the parent Company issued 3,186,006,476 ordinary shares of 25 cents each and following the acquisition issued a further 42,267,402 ordinary shares in respect of ARCO preference shares surrendered and ARCO employee share options exercised. The authorized ordinary share capital of BP Amoco p.l.c. at December 31, 1999 was 24 billion ordinary shares of 25 cents each and at December 31, 1998 the authorized ordinary share capital was 12 billion ordinary shares of 50 cents each. The allotted, called up and fully paid share capital at December 31, was as follows: <TABLE> <CAPTION> Shares --------------------- Authorized Issued Amount ----------- --------- -------- ($ million) <S> <C> <C> <C> Non-equity-- preference shares 8% cumulative first preference shares of(pound)1 each at December 31, 2000, 1999 and 1998.............. 7,250,000 7,232,838 12 =========== ========= ======== 9% cumulative second preference shares of(pound)1 each at December 31, 2000, 1999 and 1998.............. 5,500,000 5,473,414 9 =========== ========= ======== Equity--ordinary shares of 25 cents each Authorized December 31, 2000............................. 36,000,000,000 ============== </TABLE> <TABLE> <CAPTION> Years ended December 31, ---------------------------------------------------------------------------- 2000 1999 1998 ---------------------- ---------------------- ---------------------- ISSUED Shares of Shares of Shares of 25 cents each Amount 25 cents each Amount 50 cents each Amount ------------- ------ ------------- ------ ------------- ------ (thousands) ($ million) (thousands) ($ million) (thousands) ($ million) <S> <C> <C> <C> <C> <C> <C> January 1................ 19,484,024 4,871 19,366,020 4,842 9,597,793 4,309 Exchange adjustment...... -- -- -- -- -- 17 Employee share schemes... 38,112 9 66,162 16 29,833 13 Share dividend plan...... -- -- 51,842 13 110,285 46 ARCO acquisition......... 3,228,274 807 -- -- -- -- Share buyback............ (221,663) (55) -- -- (54,901) (27) Redenomination of shares into US dollars........ -- -- -- -- -- 484 ---------- -------- ---------- -------- --------- -------- December 31.............. 22,528,747 5,632 19,484,024 4,871 9,683,010 4,842 ========== ======== ========== ======== ========= ======== Paid in surplus January 1................ 3,684 3,386 3,777 Exchange adjustment...... -- -- 22 Premium on shares issued: Employee share schemes. 250 250 75 Share dividend plan ... -- (13) (46) Share buyback............ 55 -- -- Stamp duty reserve tax... (295) -- -- Qualifying Employee Share Ownership Trust (d).... 76 61 42 Redenomination of shares into US dollars........ -- -- (484) -------- -------- -------- December 31.............. 3,770 3,684 3,386 ======== ======== ======== </TABLE> The Notes to Financial Statements are an integral part of this Statement. F - 5
STATEMENT OF CHANGES IN BP SHAREHOLDERS' INTEREST (Concluded) <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Merger reserve January 1.......................................... 697 697 650 Employee share schemes............................. -- -- 97 ARCO acquisition................................... 26,172 -- -- Share buyback...................................... -- -- (50) ------ ------ ------ December 31........................................ 26,869 697 697 ====== ====== ====== Other reserves January 1.......................................... -- -- -- ARCO acquisition................................... 456 -- -- ------ ------ ------ December 31........................................ 456 -- -- ====== ====== ====== Retained earnings January 1.......................................... 34,008 33,555 33,746 Exchange adjustment................................ (2,508) (921) 16 Share dividend plan................................ -- 311 1,243 Share buyback...................................... (2,001) -- (507) Qualifying Employee Share Ownership Trust (d)...... (76) (61) (42) Profit for the year................................ 11,870 5,008 3,220 Dividends (c) Preference (non-equity)........................... (2) (2) (1) Ordinary (equity)................................. (4,623) (3,882) (4,120) ------ ------ ------ December 31........................................ 36,668 34,008 33,555 ====== ====== ====== </TABLE> ---------- (a) During 2000 there were no BP ordinary shares (1999, 51,842,146 and 1998, 110,285,094) issued under the share dividend plan at par value, by capitalization of paid in surplus. (b) Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every (pound)5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show of hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each. In the event of the winding up of the Company preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value. (c) See Note 10-- Dividends per ordinary share. (d) See Note 33-- Employee share schemes. (e) See Note 30-- Retained earnings. The Notes to Financial Statements are an integral part of this Statement. F - 6
NOTES TO FINANCIAL STATEMENTS Note 1 -- Accounting policies Accounting standards These accounts are prepared in accordance with applicable UK accounting standards. The Group has adopted Financial Reporting Standard No.15 `Tangible Fixed Assets' and Financial Reporting Standard No.16 `Current Tax' with effect from January 1, 2000. Basis of preparation The Group's main activities are the exploration and production of crude oil and natural gas; the marketing and trading of gas and power; the refining, marketing, supply and transportation of petroleum products; and the manufacturing and marketing of petrochemicals. The preparation of financial statements in conformity with UK generally accepted accounting principles requires that management make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses; and the disclosure of contingent assets and liabilities. Actual results could differ from the estimates and assumptions used. Group consolidation The Group financial statements comprise a consolidation of the accounts of the parent Company and its subsidiary undertakings (subsidiaries). The results of subsidiaries acquired or sold are consolidated for the periods from or to the date on which control passes. An associated undertaking (associate) is an entity in which the Group has a long-term equity interest and over which it exercises significant influence. The consolidated financial statements include the Group proportion of the operating profit or loss, exceptional items, stock holding gains or losses, interest expense, taxation and net assets of associates (the equity method). A joint venture is an entity in which the Group has a long-term interest and shares control with one or more co-venturers. The consolidated financial statements include the Group proportion of turnover, operating profit or loss, exceptional items, stock holding gains or losses, interest expense, taxation, gross assets and gross liabilities of the joint venture (the gross equity method). Certain of the Group's activities are conducted through joint arrangements and are included in the consolidated financial statements in proportion to the Group's interest in the income, expenses, assets and liabilities of these joint arrangements. On the acquisition of a subsidiary, or of an interest in a joint venture or associate, fair values reflecting conditions at the date of acquisition are attributed to the identifiable net assets acquired. When the cost of acquisition exceeds the fair values attributable to the Group's share of such net assets the difference is treated as purchased goodwill. This is capitalized and amortized over its estimated useful economic life, limited to a maximum period of 20 years. Accounting convention The accounts are prepared under the historical cost convention. Historical cost accounts show the profits available to shareholders and are the most appropriate basis for presentation of the Group's balance sheet. Profit or loss determined under the historical cost convention includes stock holding gains or losses and, as a consequence, does not necessarily reflect underlying trading results. F - 7
NOTES TO FINANCIAL STATEMENTS (Continued) Note 1-- Accounting policies (continued) Replacement cost The results of individual businesses and geographical areas are presented on a replacement cost basis. Replacement cost operating results exclude inventory holding gains or losses and reflect the average cost of supplies incurred during the year, and thus provide insight into underlying trading results. Inventory holding gains or losses represent the difference between the replacement cost of sales and the historical cost of sales calculated using the first-in, first-out, method. Inventory valuation Inventories are valued at cost to the Group using the first-in, first-out, method or at net realizable value, whichever is the lower. Stores are stated at or below cost calculated mainly using the average method. Revenue recognition Revenues associated with the sale of oil, natural gas liquids, liquefied natural gas, petroleum and chemical products and all other items are recognized when the title passes to the customer. Generally, revenues from the production of natural gas and oil properties in which the Group has an interest with other producers, are recognized on the basis of the Group's working interest in those properties (the entitlement method). Differences between the production sold and the Group's share of production are not significant. Foreign currencies On consolidation, assets and liabilities of subsidiaries are translated into US dollars at closing rates of exchange. Income and cash flow statements are translated at average rates of exchange. Exchange differences resulting from the retranslation of net investments in subsidiaries and associates at closing rates, together with differences between income statements translated at average rates and at closing rates, are dealt with in reserves. Exchange gains and losses arising on long-term foreign currency borrowings used to finance the Group's foreign currency investments are also dealt with in reserves. All other exchange gains or losses on settlement or translation at closing rates of exchange of monetary assets and liabilities are included in the determination of profit for the year. Derivative financial instruments The Group uses derivative financial instruments (derivatives) to manage certain exposures to fluctuations in foreign currency exchange rates and interest rates, and to manage some of its margin exposure from changes in oil and natural gas prices. Derivatives are also traded in conjunction with these risk management activities. The purpose for which a derivative contract is used is identified at inception. To qualify as a derivative for risk management, the contract must be in accordance with established guidelines which ensure that it is effective in achieving its objective. All contracts not identified at inception as being for the purpose of risk management are designated as being held for trading purposes and accounted for using the fair value method, as are all oil price derivatives. The Group accounts for derivatives using the following methods: Fair value method: derivatives are carried on the balance sheet at fair value ('marked to market') with changes in that value recognized in earnings of the period. This method is used for all derivatives which are held for trading purposes. Interest rate contracts traded by the Group include futures, swaps, options and swaptions. Foreign exchange contracts traded include forwards and options. Oil price contracts traded include swaps, options and futures. Accrual method: amounts payable or receivable in respect of derivatives are recognized ratably in earnings over the period of the contracts. This method is used for derivatives held to manage interest rate risk. These are principally swap agreements used to manage the balance between fixed and floating interest rates on long-term finance debt. Other derivatives held for this purpose may include swaptions and futures contracts. Amounts payable or receivable in respect of these derivatives are recognized as adjustments to interest expense over the period of the contracts. Changes in the derivative's fair value are not recognized. F - 8
NOTES TO FINANCIAL STATEMENTS (Continued) Note 1-- Accounting policies (continued) Derivative financial instruments (continued) Deferral method: gains and losses from derivatives are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. This method is used for derivatives used to convert non-US dollar borrowings into US dollars, to hedge significant non-US dollar firm commitments or anticipated transactions, and to manage some of the Group's exposure to natural gas price fluctuations. Derivatives used to convert non-US dollar borrowings into US dollars include foreign currency swap agreements and forward contracts. Gains and losses on these derivatives are deferred and recognized on maturity of the underlying debt, together with the matching loss or gain on the debt. Derivatives used to hedge significant non-US dollar transactions include foreign currency forward contracts and options and to hedge natural gas price exposures include swaps, futures and options. Gains and losses on these contracts and option premia paid are also deferred and recognized in the income statement or as adjustments to carrying amounts, as appropriate, when the hedged transaction occurs. Where derivatives used to manage interest rate risk or to convert non-US dollar debt or to hedge other anticipated cash flows are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis which matches the timing and accounting treatment of the underlying debt or hedged transaction. When an anticipated transaction is no longer likely to occur or finance debt is terminated before maturity, any deferred gain or loss that has arisen on the related derivative is recognized in the income statement together with any gain or loss on the terminated item. Depreciation Oil and gas production assets are depreciated using a unit-of-production method based upon estimated proved reserves. Other tangible and intangible assets are depreciated on the straight line method over their estimated useful lives. The average estimated useful lives of refineries are 20 years, chemicals manufacturing plants 20 years and service stations 15 years. Other intangibles are amortized over a maximum period of 20 years. The Group undertakes a review for impairment of a fixed asset or goodwill if events or changes in circumstances indicate that the carrying amount of the fixed asset or goodwill may not be recoverable. To the extent that the carrying amount exceeds the recoverable amount, that is the higher of net realizable value and value in use, the fixed asset or goodwill is written down to its recoverable amount. The value in use is determined from estimated discounted future net cash flows. Maintenance expenditure Expenditure on major maintenance, refits or repairs is capitalized where it enhances the performance of an asset above its originally assessed standard of performance; replaces an asset or part of an asset which was separately depreciated and which is then written off; or restores the economic benefits of an asset which has been fully depreciated. All other maintenance expenditure is charged to income as incurred. Exploration expenditure Exploration expenditure is accounted for in accordance with the successful efforts method. Exploration and appraisal drilling expenditure is initially capitalized as an intangible fixed asset. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is transferred to tangible production assets. All exploration expenditure determined as unsuccessful is charged against income. Exploration licence acquisition costs are amortized over the estimated period of exploration. Geological and geophysical exploration costs are charged against income as incurred. F - 9
NOTES TO FINANCIAL STATEMENTS (Continued) Note 1-- Accounting policies (continued) Decommissioning Provision for decommissioning is recognized in full at the commencement of oil and natural gas production. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. A corresponding tangible fixed asset of an amount equivalent to the provision is also created. This is subsequently depreciated as part of the capital costs of the production and transportation facilities. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the fixed asset. Petroleum revenue tax The charge for petroleum revenue tax is calculated using a unit-of-production method. Changes in unit-of-production factors Changes in factors which affect unit-of-production calculations are dealt with prospectively, not by immediate adjustment of prior years' amounts. Environmental liabilities 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 contribute to current or 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, on divestment or on closure of inactive sites. The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years the amount recognized is the present value of the estimated future expenditure. Leases Assets held under leases which result in Group companies receiving substantially all risks and rewards of ownership (finance leases) are capitalized as tangible fixed assets at the estimated present value of underlying lease payments. The corresponding finance lease obligation is included with borrowings. Rentals under operating leases are charged against income as incurred. Research Expenditure on research is written off in the year in which it is incurred. Interest Interest is capitalized gross during the period of construction where it relates either to the financing of major projects with long periods of development or to dedicated financing of other projects. All other interest is charged against income. Pensions and other postretirement benefits The cost of providing pensions and other postretirement benefits is charged to income on a systematic basis, with pension surpluses and deficits amortized over the average expected remaining service lives of current employees. The difference between the amounts charged to income and the contributions made to pension plans is included within other provisions or debtors as appropriate. The amounts accrued for other postretirement benefits and unfunded pension liabilities are included within other provisions. F - 10
NOTES TO FINANCIAL STATEMENTS (Continued) Note 1-- Accounting policies (concluded) Deferred taxation Deferred taxation is calculated, using the liability method, in respect of timing differences arising primarily from the difference between the accounting and tax treatments of both depreciation and petroleum revenue tax. Provision is made or recovery anticipated where timing differences are expected to reverse in the foreseeable future. Discounting The unwinding of the discount on provisions is included within interest expense. Any change in the amount recognized for environmental and other provisions arising through changes in discount rates is included within interest expense. Comparative figures Certain previous years' figures have been changed to conform with the 2000 presentation. Note 2 -- Turnover <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and operating revenue.......................... 168,709 91,891 76,448 Customs duties and sales taxes....................... 20,647 8,325 8,144 ------ ------ ------ 148,062 83,566 68,304 ====== ====== ====== </TABLE> Note 3 -- Production taxes <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> UK petroleum revenue tax............................. 707 237 45 Overseas production taxes............................ 1,354 780 559 ------ ------ ------ 2,061 1,017 604 ====== ====== ====== </TABLE> Note 4 -- Distribution and administration expenses <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Distribution................................................ 6,718 5,031 4,714 Administration.............................................. 1,817 1,033 1,330 ------ ------ ------ 8,535 6,064 6,044 ====== ====== ====== </TABLE> F - 11
NOTES TO FINANCIAL STATEMENTS (Continued) Note 5 -- Other income <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Income from other fixed asset investments................... 202 66 74 Other interest and miscellaneous income..................... 603 348 635 ------ ------ ------ 805 414 709 ====== ====== ====== Income from investments publicly traded included above...... 8 14 10 ------ ------ ------ </TABLE> Note 6 -- Exceptional items Exceptional items comprise profit (loss) on sale of businesses and fixed assets, restructuring costs and merger expenses, as follows: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Profit on sale of businesses - --Group..................................................... 341 427 310 - --Joint ventures............................................ -- 42 85 Loss on sale of businesses -- Group......................... (209) (106) -- ------ ------ ------ 132 363 395 Profit on sale of fixed assets - --Group..................................................... 535 84 653 - --Joint ventures............................................ 24 -- -- Loss on sale of fixed assets -- Group....................... (471) (784) -- ------ ------ ------ 88 (700) 653 ------ ------ ------ 220 (337) 1,048 Restructuring costs - --Group..................................................... -- (1,900) -- - --Joint ventures............................................ -- (43) -- Merger expenses -- Group.................................... -- -- (198) ------ ------ ------ Exceptional items........................................... 220 (2,280) 850 Taxation credit (charge): Sale of businesses.......................................... (181) (21) (36) Sale of fixed assets........................................ (111) (29) (185) Restructuring costs......................................... -- 280 -- Merger expenses............................................. -- -- 23 ------ ------ ------ Exceptional items, net of tax............................... (72) (2,050) 652 ====== ====== ====== </TABLE> F - 12
NOTES TO FINANCIAL STATEMENTS (Continued) Note 6 -- Exceptional items (concluded) Sales of businesses The profit on the sale of businesses during 2000 is attributable primarily to the divestment by the Group of its common interest in Altura Energy. For 1999 the profit related mainly to the divestment by the Group of its Canadian oil properties and certain chemicals businesses. These included the Verdugt acid salts business; the Plaskon electronics materials business located in the USA and Singapore; and the US Fibers and Yarns business. The profit on sale of businesses by joint ventures in 1999 was mainly attributable to the disposal by the BP/Mobil joint venture of its retail network in Hungary. In 1998 the principal sales of businesses were exploration and production properties in the USA and Papua New Guinea, the retail network in the Czech Republic, the Adibis fuel additives business and a speciality chemicals distribution business. The profit on sale of businesses by joint ventures related mainly to the disposal by the BP/Mobil joint venture of its retail network in Belgium. For 2000 the loss on sale of businesses relates to the subvention of bank loans to its paraxylene joint venture in Singapore. The loss during 1999 arose from the closure of this joint venture. Sale of fixed assets The profit on the sale of fixed assets in 2000 includes the profit from the disposal of the Alliance refinery, located in Belle Chasse, Louisiana, the profit from the divestment of a 10% interest in certain exploration and production interests in Trinidad and the profit from the sale of other exploration and production interests, mainly in the UK and USA. For 1999 the sale of fixed assets included the Federal Trade Commission-mandated sale of distribution terminals and service stations in the USA, the divestment by the Group of its interest in an olefins cracker at Wilton in the UK and the sale and leaseback of US railcars. In 1998 the profit on the sale of fixed assets arose principally from the divestment of the refinery in Lima, Ohio, and the sale and leaseback of the Amoco building in Chicago. For 2000 the loss on sale of fixed assets relates principally to the divestment by the Group of its interests in the Quiriquire and Guarapiche fields in Venezuela. The major element of the loss in 1999 was the disposal by the Group of its interest in the Pedernales oil field in Venezuela. Additional information on the sale of businesses and fixed assets is given in Note 18 -- Disposals. Restructuring costs These costs arose from restructuring activity across the Group following the merger of BP and Amoco at the end of 1998 and relate predominantly to the Group's US operations. The major elements of the restructuring charges comprise employee severance costs ($1,212 million) and provisions to cover future rental payments on surplus leasehold office accommodation and other property ($297 million). During 1999, some 16,000 employees left the Group through severance or outsourcing arrangements. Also included in the restructuring charges are office closure costs, contract termination payments and asset write-downs. The cash outflow for these restructuring charges during 1999 was $976 million and during 2000 was $446 million. Merger expenses BP incurred fees and expenses of $198 million in connection with the merger of BP and Amoco. These costs relate principally to investment banking fees as well as legal, accounting and regulatory filing fees. F - 13
NOTES TO FINANCIAL STATEMENTS (Continued) Note 7 -- Interest expense <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Bank loans and overdrafts............................ 154 119 158 Other loans.......................................... 1,221 854 762 Finance leases....................................... 107 75 90 ------ ------ ------ 1,482 1,048 1,010 Capitalized at 7% (1999 6% and 1998 7%).............. 119 43 119 ------ ------ ------ Group................................................ 1,363 1,005 891 Joint ventures....................................... 78 70 54 Associated undertakings.............................. 140 131 108 Unwinding of discount on provisions ................. 189 130 124 Change in discount rate for provisions .............. -- (20) -- ------ ------ ------ Total charged against profit......................... 1,770 1,316 1,177 ====== ====== ====== </TABLE> Interest expense includes a charge of $111 million (1999 $24 million and 1998 $12 million) relating to early redemption of debt. Note 8 -- Depreciation and amounts provided Included in the income statement under the following headings: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Depreciation: Replacement cost of sales.......................... 6,403 4,185 4,666 Distribution....................................... 707 408 335 Administration..................................... 87 115 100 Exceptional items.................................. -- 258 -- ------ ------ ------ 7,197 4,966 5,101 ====== ====== ====== Depreciation of capitalized leased assets included above 79 70 71 ------ ------ ------ Amounts provided against fixed asset investments: Exceptional items.................................. -- 84 -- Replacement cost of sales.......................... 252 (1) 200 ------ ------ ------ 252 83 200 ====== ====== ====== </TABLE> The charge for depreciation and amortization of goodwill in 2000 includes $61 million for the write-down of Chemicals and Exploration and Production assets. In addition $181 million has been provided against the Group's chemicals investment in Indonesia as a result of the continuing weak business environment in the region. The rationalization of office and other facilities in 1999 following the merger resulted in the write-off of redundant IT and other office equipment and furnishings. This charge of $258 million has been included within exceptional items. In addition for 1999 the charge for depreciation includes $100 million for the impairment of the Badami field in Alaska and $123 million for the write-down of various Chemicals and Refining and Marketing assets. The charge for depreciation in 1998 included $214 million for the impairment of the Opon field in Colombia and $61 million for the write-down of various other oil and natural gas properties. The impairment of the Opon field reflected lower than anticipated natural gas production and related reserve estimates. The charge also reflected impairment of the adjacent power plant because of the unavailability of an economic fuel supply. As a result of increased economic uncertainty in Russia, the Group wrote down the carrying value of its investment in A O Sidanco by $200 million. In assessing the value in use of potentially impaired assets, a discount rate of 9% has been used. This is the rate used by the Company for investment appraisal. F - 14
NOTES TO FINANCIAL STATEMENTS (Continued) Note 9 -- Taxation Charge for taxation <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> United Kingdom corporation tax: Current at 30.0% (1999 at 30.25% and 1998 at 31.0%) 1,505 875 1,325 Overseas tax relief................................ (310) (363) (566) ------ ------ ------ 1,195 512 759 Deferred at 30.0% (1999 at 30.0% and 1998 at 31.0%) 12 91 (188) ------ ------ ------ 1,207 603 571 Advance corporation tax............................ -- -- (76) ------ ------ ------ 1,207 603 495 ------ ------ ------ Overseas: Current............................................ 3,704 1,143 896 Deferred........................................... (124) 30 (4) Joint ventures..................................... -- 5 (15) Associated undertakings............................ 185 99 148 ------ ------ ------ 3,765 1,277 1,025 ------ ------ ------ Taxation charge for the year......................... 4,972 1,880 1,520 ====== ====== ====== </TABLE> Included in the charge for the year is a charge of $292 million (1999 $230 million credit and 1998 $198 million charge) relating to exceptional items. Provisions for deferred taxation <TABLE> <CAPTION> Gross potential Provisions liability --------------- --------------- Years ended December 31, --------------------------------- 2000 1999 2000 1999 ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Analysis of movements during the year: At January 1........................................ 1,783 1,632 7,139 6,618 Exchange adjustments................................ (139) 30 (262) (42) Acquisitions........................................ 323 -- 1,404 -- Charge (credit) for the year........................ (112) 121 1,442 563 Deletions/transfers................................. (33) -- (39) -- ------ ------ ------ ------ At December 31...................................... 1,822 1,783 9,684 7,139 ====== ====== ====== ====== of which -- United Kingdom.......................... 1,141 1,015 1,436 1,482 -- Overseas................................ 681 768 8,248 5,657 ====== ====== ====== ====== </TABLE> F - 15
NOTES TO FINANCIAL STATEMENTS (Continued) Note 9 -- Taxation (continued) <TABLE> <CAPTION> Gross potential Provisions liability --------------- --------------- Years ended December 31, --------------------------------- 2000 1999 2000 1999 ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Analysis of provision: Depreciation........................................ 2,641 2,567 13,008 10,279 Petroleum revenue tax............................... (337) (332) (337) (332) Other timing differences............................ (482) (452) (2,987) (2,808) ------ ------ ------ ------ 1,822 1,783 9,684 7,139 ====== ====== ====== ====== </TABLE> If provision for deferred taxation had been made on the basis of the gross potential liability, the taxation charge for the year would have been increased (decreased) as follows: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> United Kingdom................................................. (122) (185) (40) Overseas....................................................... 1,676 627 409 ------ ------ ------ 1,554 442 369 ====== ====== ====== </TABLE> Deferred taxation is not generally provided in respect of liabilities which may arise on the distribution of accumulated reserves of overseas subsidiaries, joint ventures and associates. Reconciliation of the UK statutory tax rate to the effective tax rate of the Group on replacement cost profit before exceptional items <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ (% of profit before tax) <S> <C> <C> <C> United Kingdom statutory tax rate.............................. 30 30 31 Increase (decrease) resulting from: Current year timing differences not provided (including current year losses unrelieved/prior year losses utilized)..................................... (5) (10) (6) Tax on inventory holding gains (relief for inventory holding losses).................................. 1 2 (3) Overseas taxes at higher rates............................... 7 5 4 Tax credits.................................................. (4) -- (2) Acquisition amortization..................................... 3 -- -- Advance corporation tax...................................... -- -- (1) Other........................................................ (3) 1 2 ------ ------ ------ Effective tax rate on replacement cost profit before exceptional items.......................................... 29 28 25 ====== ====== ====== </TABLE> Further information presented in compliance with the requirements of FASB Statement of Financial Accounting Standards No. 109 -- 'Accounting For Income Taxes' is set out below. F - 16
NOTES TO FINANCIAL STATEMENTS (Continued) Note 9 -- Taxation (concluded) Effective tax rate <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Analysis of profit before taxation: United Kingdom....................................... 3,426 1,663 2,269 Overseas............................................. 13,508 5,363 2,534 ------ ------ ------ 16,934 7,026 4,803 ====== ====== ====== Taxation............................................. 4,972 1,880 1,520 ====== ====== ====== Effective tax rate................................... 29% 27% 32% ====== ====== ====== </TABLE> The following relates the United Kingdom statutory tax rate to the effective tax rate of the Group based on profit before taxation: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ (% of profit before tax) <S> <C> <C> <C> United Kingdom statutory tax rate.................... 30 30 31 Increase (decrease) resulting from: Current year timing differences not provided....... (5) (9) (12) (Prior year losses utilized) current year losses unrelieved.......................... 2 2 5 (Inventory holding gains not taxed) no relief for inventory holding losses......................... (1) (5) 5 Overseas taxes at higher rates..................... 7 5 7 Tax credits........................................ (4) -- (2) Advance corporation tax............................ -- -- (2) Acquisition amortization ............................ 3 1 1 Other ............................................. (3) 3 (1) ------ ------ ------ Effective tax rate................................... 29 27 32 ====== ====== ====== </TABLE> F - 17
NOTES TO FINANCIAL STATEMENTS (Continued) Note 10 -- Dividends per ordinary share <TABLE> <CAPTION> Years ended December 31, -------------------------------------------------------------- 2000 1999 1998 2000 1999 1998 2000 1999 1998 ------ ------ ------ ------ ------ ------ ------ ------ ------ (pence per share) (cents per share) ($ million) BP <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Dividends per ordinary share: First quarterly........... 3.220 3.069 -- 5.00 5.00 -- 1,133 970 -- Second quarterly.......... 3.352 3.112 -- 5.00 5.00 -- 1,128 970 -- Third quarterly........... 3.602 3.033 -- 5.25 5.00 -- 1,185 971 -- Fourth quarterly.......... 3.617 3.125 3.059 5.25 5.00 5.00 1,177 971 968 ------ ------ ------ ------ ------ ------ ------ ------ ------ 13.791 12.339 3.059 20.50 20.00 5.00 4,623 3,882 968 ------ ------ ------ ------ ------ ------ ------ ------ ------ The British Petroleum Company p.l.c. Dividends per ordinary share: First quarterly........... 2.875 4.75 551 Second quarterly.......... 3.000 5.00 579 Third quarterly........... 3.000 5.00 584 Fourth quarterly.......... -- -- -- ------ ------ ------ 8.875 14.75 1,714 ------ ------ ------ Amoco Dividends per common stock: First quarterly........... 18.75 362 Second quarterly.......... 18.75 360 Third quarterly........... 18.75 358 Fourth quarterly.......... 18.75 358 ------ ------ 75.00 1,438 ------ ------ ------ ------ Total Group............... 4,623 3,882 4,120 ====== ====== ====== </TABLE> On an ordinary share equivalent basis, the Amoco quarterly dividends for 1998 was 4.7 cents. F - 18
NOTES TO FINANCIAL STATEMENTS (Continued) Note 11 -- Profit per ordinary share <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ (cents per share) <S> <C> <C> <C> Basic earnings per share....................................... 54.85 25.82 16.77 Diluted earnings per share..................................... 54.48 25.68 16.70 </TABLE> The calculation of basic earnings per ordinary share is based on the profit attributable to ordinary shareholders, i.e. profit for the year less preference dividends, related to the weighted average number of ordinary shares in issue during the year. The profit attributable to ordinary shareholders is $11,868 million (1999 $5,006 million and 1998 $3,219 million). The average number of shares outstanding excludes the shares held by the Employee Share Ownership Plans. The calculation of diluted earnings per share is based on profit attributable to ordinary shareholders as for basic earnings per share. However, the number of shares outstanding is adjusted to show the potential dilution if employee share options are converted into ordinary shares. The number of ordinary shares outstanding for basic and diluted earnings per share may be reconciled as follows: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ (shares million) <S> <C> <C> <C> Weighted average number of ordinary shares..................... 21,638 19,386 19,192 Ordinary shares issuable under employee share schemes.......... 145 111 84 ------ ------ ------ 21,783 19,497 19,276 ====== ====== ====== </TABLE> In addition to basic earnings per share based on the historical cost profit for the year, a further measure, based on replacement cost profit before exceptional items, is provided as it is considered that this measure gives an indication of underlying performance. <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ (cents per share) <S> <C> <C> <C> Profit for the year............................................ 54.85 25.82 16.77 Inventory holding (gains) losses............................... (3.36) (8.91) 7.25 ------ ------ ------ Replacement cost profit for the year........................... 51.49 16.91 24.02 Exceptional items, net of tax.................................. 0.33 10.57 (3.40) ------ ------ ------ Replacement cost profit before exceptional items............... 51.82 27.48 20.62 ====== ====== ====== </TABLE> F - 19
NOTES TO FINANCIAL STATEMENTS (Continued) Note 12-- Quarterly results of operations (unaudited) <TABLE> <CAPTION> Historical cost Profit per Group profit before Profit ordinary turnover interest and tax (loss) share -------- ---------------- ------ ---------- ($ million) (cents) <S> <C> <C> <C> <C> Year ended December 31, 2000 First quarter............................. 33,091 4,336 3,085 15.88 Second quarter............................ 39,027 4,711 3,024 13.59 Third quarter............................. 44,862 5,377 3,351 14.85 Fourth quarter............................ 44,846 4,280 2,410 10.53 -------- ---------------- ------ ---------- Total..................................... 161,826 18,704 11,870 54.85 ========= ================ ====== ========== Year ended December 31, 1999 First quarter............................. 17,984 195 (176) (0.91) Second quarter............................ 22,939 2,461 1,635 8.44 Third quarter............................. 26,665 2,990 1,848 9.53 Fourth quarter............................ 33,592 2,696 1,701 8.76 -------- ---------------- ------ ---------- Total..................................... 101,180 8,342 5,008 25.82 ========= ================ ====== ========== </TABLE> Note 13 -- Rental expense under operating leases <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Minimum rentals: Tanker charters.................................... 361 357 396 Plant and machinery................................ 471 509 429 Land and buildings................................. 343 271 315 ------ ------ ------ 1,175 1,137 1,140 Less: Rentals from sub-leases........................ (185) (178) (105) ------ ------ ------ 990 959 1,035 ====== ====== ====== </TABLE> Note 14 -- Research and development Expenditure on research and development amounted to $434 million (1999 $310 million and 1998 $412 million). F - 20
NOTES TO FINANCIAL STATEMENTS (Continued) Note 15 -- Auditors' remuneration <TABLE> <CAPTION> Years ended December 31, -------------------------------------------------- 2000 1999 1998 --------------- --------------- --------------- UK Total UK Total UK Total ------ ------ ------ ------ ------ ------ ($million) <S> <C> <C> <C> <C> <C> <C> Audit fees-- Ernst & Young: Group audit......................... 6 15 6 14 6 12 Local statutory audit and quarterly review.............. 2 13 1 6 1 5 ------ ------ ------ ------ ------ ------ 8 28 7 20 7 17 ------ ------ ------ ------ ------ ------ Audit fees -- PricewaterhouseCoopers LLP: Group audit......................... -- -- -- -- -- 3 Local statutory audit and quarterly review.............. -- -- -- -- -- 1 ------ ------ ------ ------ ------ ------ -- -- -- -- -- 4 ------ ------ ------ ------ ------ ------ Total Group........................... 8 28 7 20 7 21 ====== ====== ====== ====== ====== ====== Fees for other services -- Ernst & Young Acquisitions and disposals.......... 8 9 3 5 2 4 Taxation services................... 2 14 1 6 1 4 Assurance services.................. 5 10 4 5 4 6 Consultancy......................... 5 18 7 20 2 11 ------ ------ ------ ------ ------ ------ 20 51 15 36 9 25 ====== ====== ====== ====== ====== ====== </TABLE> 2000 Group audit fees include $1 million (1999 $1 million and 1998 $1 million) for excess of actual over estimated fees for 1999. Fees to major firms of accountants other than Ernst &Young for non-audit services amounted to $411 million (1999 $160 million and 1998 $181 million). Note 16 -- Currency exchange gains and losses Accounted net foreign currency exchange gain included in the determination of profit for the year amounted to $30 million (1999 $17 million gain and 1998 $23 million loss). F - 21
NOTES TO FINANCIAL STATEMENTS (Continued) Note 17 -- Acquisitions In 2000 the Company acquired Atlantic Richfield Company (ARCO) and Burmah Castrol plc (Burmah Castrol) and the 18% minority interest in Vastar Resources Inc. (Vastar), a subsidiary of ARCO. The Company also purchased most of ExxonMobil's assets used by the fuels refining and marketing operation in Europe and made a number of minor acquisitions. All these business combinations have been been accounted for using the acquisition method of accounting. The goodwill arising on the ARCO and Burmah Castrol acquisitions is being amortized over 10 years. ARCO acquisition On April 13 the acquisition of ARCO by BP was cleared by the US Federal Trade Comission and thereby became unconditional. The transaction was closed on April 18, 2000. The last day of trading in ARCO common stock was April 17, 2000. The results of ARCO have been consolidated from April 14. ARCO shareholders received for each share of ARCO common stock held as of April 17, 2000, 9.84 BP ordinary shares. Such BP ordinary shares were delivered in the form of BP ADSs or, at the election of a holder of ARCO common stock, BP ordinary shares. For purposes of determining the consideration for the transaction the number of ARCO shares issued and outstanding on April 17, 2000 (324 million shares), together with the estimated number of additional shares which may be issued in respect of outstanding options and contingent stock and on conversion of ARCO preference stock (15 million shares), have been used, which would result in the issue of approximately 3,335 million BP ordinary shares. The total consideration for the acquisition was $27,506 million, including acquisition expenses of $79 million. Stamp duty reserve tax of $295 million paid on the issue of ADSs has been treated as a share issue expense and charged against the Share Premium Account. The assets and liabilities of ARCO and the fair value adjustments made are set out below: <TABLE> <CAPTION> Fair value adjustments -------------------------- Accounting Book value policy Fair on acquisitions alignment Revaluations value --------------- ------------ ------------ --------- ($ million) <S> <C> <C> <C> <C> Intangible fixed assets................ 1,358 (20) 1,211 2,549 Tangible fixed assets.................. 12,088 (2,208) 9,949 19,829 Fixed asset investments................ 2,858 (447) 594 3,005 Net assets of operations held for sale. 4,293 -- 997 5,290 Current assets (excluding cash)........ 3,326 297 45 3,668 Cash at bank and in hand............... 994 -- -- 994 Finance debt........................... (6,431) -- (365) (6,796) Other creditors........................ (2,539) (649) (287) (3,475) Deferred taxation...................... (3,643) 3,320 -- (323) Other provisions....................... (2,761) (104) (144) (3,009) ------- ------- ------- ------- Net assets acquired.................... 9,543 189 12,000 21,732 ------- ------- ------- Minority interests..................... (1,595) Goodwill............................... 7,369 ------- Consideration.......................... 27,506 ======= </TABLE> F - 22
NOTES TO FINANCIAL STATEMENTS (Continued) Note 17 -- Acquisitions (continued) Fair Values The methods and assumptions set out in the following paragraphs were used in estimating the fair value of the assets and liabilities acquired. Intangible and tangible fixed assets. The fair value of the tangible and intangible assets has mainly been estimated by determining the net present value of future cash flows. The cash flows were discounted at the rate used by the Company for investment appraisal, namely 9%. Fixed asset investment. The fair value of listed investments is based on quoted market prices. Net assets of operations held for sale. The fair value of the net assets of these operations reflects the sales proceeds, less attributable taxation. Finance debt. The fair value of ARCO long term debt, including current maturities, has been estimated based on the quoted market prices for the same or similar issues. Other creditors. Accruals for sundry liabilities existing at the date of acquisition. Other provisions. Liabilities for pensions and other post-retirement benefits have been estimated by independent actuaries. Provisions for other liabilities have been reassessed at the acquisition date and revalued in line with BP practice. Accounting policy alignment The accounting policy alignment adjustments represent the adjustments necessary to restate the balance sheet of ARCO prepared under US GAAP to conform with BP's accounting policies under UK GAAP. The principal adjustments are set out below. Tangible fixed assets. The adjustments mainly reflect restatement of tangible fixed assets to recoverable amount where this is less than carrying value ($1,388 million), the elimination of deferred tax gross up on business combinations ($1,131 million), and the capitalization of decommissioning assets ($176 million). Fixed asset investments. Restatement to historical cost rather than current market value. Current assets. The basis of stock valuation changed from last-in first-out to first-in first-out. Other creditors. Reclassification of corporate taxes payable. Deferred taxation. Restatement of deferred tax liabilities on a restricted liability basis ($1,338 million) and the elimination of deferred tax gross up on business combinations ($1,131 million). Other provisions. Restatement on a discounted basis of environmental and other provisions and recognition of the full liability for decommissioning on a discounted basis. F - 23
NOTES TO FINANCIAL STATEMENTS (Continued) Note 17 -- Acquisitions (continued) The summarized income statement and statement of total recognized gains and losses of ARCO for the period January 1, 2000 to April 13, 2000, being the period from the beginning of ARCO's financial year to the effective date of the acquisition, are shown below. Also shown below is the summarized income statement for the financial year ended December 31, 1999. This information is presented on a US GAAP basis and includes the results of those operations which were sold as required by the US Federal Trade Commission. Summarized income statement <TABLE> <CAPTION> Period Year January 1 ended to April 13, December 31, 2000 1999 ----------- ----------- ($ million) <S> <C> <C> Turnover.................................................... 4,930 13,055 ------ ------ Profit before interest and taxation......................... 1,056 2,391 Interest.................................................... 125 398 ------ ------ Profit before taxation...................................... 931 1,993 Taxation.................................................... 291 533 ------ ------ Profit after taxation....................................... 640 1,460 Minority shareholders' interest............................. 18 38 ------ ------ Net Income.................................................. 622 1,422 ====== ====== </TABLE> Statement of total recognized gains and losses <TABLE> <CAPTION> Period January 1 to April 13, 2000 ----------- ($ million) <S> <C> Net income for the period................................... 622 Currency translation differences............................ (5) Unrealized gain (loss) on securities........................ 129 ------ Total recognized gains and losses........................... 746 ====== </TABLE> For the year ended December 31, 2000 ARCO contributed $12,162 million to turnover, $569 million to Group replacement cost operating profit and $518 million to historical cost profit before interest and tax. Within the Exploration and Production segment ARCO represented $4,458 million of turnover and $690 million of Group replacement cost operating profit. For the USA segment ARCO represented $9,420 million of turnover and $52 million of Group replacement cost operating profit. ARCO contributed $3,523 million to the Group's net cash inflow from operating activities, represented $295 million of net cash outflow from servicing of finance and returns on investments, represented $2,270 million of tax paid, represented $404 million of net cash outflow for capital expenditure, contributed $5,066 million of net cash inflow for acquisitions and disposals and represented $3,092 million of net cash outflow from financing. F - 24
NOTES TO FINANCIAL STATEMENTS (Continued) Note 17 -- Acquisitions (continued) The following unaudited pro forma consolidated results of operations for the Group have been prepared as if the acquisition of ARCO was effective as of January 1, 1999. <TABLE> <CAPTION> Year ended December 31, --------------------------- 2000 1999 -------- -------- ($ million, except per share amounts) <S> <C> <C> Turnover............................................................. 152,091 94,610 Historical cost profit before interest and tax....................... 18,916 8,124 Profit for the year.................................................. 11,817 4,174 Per ordinary share - cents Basic................................................................ 52.14 18.37 Diluted.............................................................. 51.81 18.28 Per American Depositary Share - cents Basic................................................................ 312.84 110.22 Diluted.............................................................. 310.86 109.68 Profit for the year applicable to ordinary shares as adjusted to accord with US GAAP...................................... 9,998 3,442 Per ordinary share - cents Basic................................................................ 44.11 15.15 Diluted.............................................................. 43.83 15.08 Per American Depositary Share - cents Basic................................................................ 264.66 90.90 Diluted.............................................................. 262.98 90.48 </TABLE> Other acquisitions BP completed the purchase of the minority interest in Vastar on September 15,2000 for a total consideration of $1,618 million. This was settled in cash and included expenses of $9 million and $94 million for the buy-out of employee share options. The identifiable assets and liabilities of Vastar have not been revalued on the acquisition of the minority interest as the difference between the fair values and the carrying amounts of the assets and liabilities is not material. On July 7, 2000, the Company declared its cash offer for Burmah Castrol unconditional. The results of Burmah Castrol have been consolidated from this date. The total consideration was $4,909 million. Apart from the issue of $130 million of loan notes the balance of the consideration has been or will be settled in cash and includes expenses of $16 million. On dissolution of the pan-European refining and marketing joint venture BP acquired most of the ExxonMobil assets used by the fuels operation for $1,479 million. This acquisition became effective on August 1, 2000, from which date the operations have been consolidated. The aggregate net assets acquired approximate the consideration paid. The Group undertook a number of other acquisitions in the year for an aggregate consideration of $100 million. No significant fair value adjustments were made to the acquired assets or liabilities. In 1999 the Group acquired the outstanding 83% of ProGas, a major Canadian natural gas supply aggregator, and 50% of Solarex, a manufacturer and developer of photovoltaic products and systems, it did not already own. Also in 1999 the Group purchased APEX, a solar electric Company based in Montpellier, France. F - 25
NOTES TO FINANCIAL STATEMENTS (Continued) Note 17 -- Acquisitions (concluded) The aggregate assets and liabilities for the Burmah Castrol, ExxonMobil fuels refining and marketing operation and other acquisitions and the fair value adjustments made are set out below: <TABLE> <CAPTION> Years ended December 31, ------------------------------------------------------------------------ 2000 1999 1998 ------------------------------------------------------ ------- ------- Fair value adjustments -------------------------- Accounting Book value policy Fair Fair Fair on acquisitions alignment Revaluations value value value --------------- ---------- ------------ ------- ------- ------- ($ million) <S> <C> <C> <C> <C> <C> <C> Intangible fixed assets........... 19 -- (19) -- 3 1 Tangible fixed assets............. 1,943 (4) -- 1,939 119 194 Fixed asset investments........... 1,080 -- -- 1,080 9 71 Business held for resale.......... 499 -- 137 636 -- -- Current assets (excluding cash)... 3,091 -- -- 3,091 10 27 Cash at bank and in hand.......... 796 -- -- 796 5 -- Finance debt...................... (1,146) -- -- (1,146) (58) (17) Other creditors................... (3,718) -- -- (3,718) (1) -- Provisions for liabilities and charges (218) (6) (21) (245) -- -- ----- ----- ----- ----- ----- ----- Net assets acquired............... 2,346 (10) 97 2,433 87 276 ----- ----- ----- ----- ----- ----- Minority interests................ (245) -- -- Goodwill.......................... 4,300 20 38 ----- ----- ----- Consideration..................... 6,488 107 314 ===== ===== ===== </TABLE> Pro forma effects as required by US GAAP, assuming the Burmah Castrol, ExxonMobil fuels refining and marketing operation and other acquisitions had taken place on January 1, 1999, are not presented as they would not materially change reported consolidated results of operations. Note 18 -- Disposals As a condition of the acquisitions of Atlantic Richfield Company (ARCO), BP was required to divest ARCO's Alaskan businesses and certain pipeline interests in the Lower 48. These operations were sold for aggregate proceeds of $6,803 million. No profit or loss arose on these disposals. Other major disposals during 2000 were the sale of the Group's common interest in Altura Energy, the sale of the Alliance refinery, the divestment of exploration and production interests in Trinidad, the UK, USA and Venezuela and the sale of the Southern Company Energy Marketing. Disposals during 1999 included the sale of the Group's Canadian oil properties; the divestment of its interest in the Pedernales oil field in Venezuela; the Federal Trade Commission-mandated sale of distribution terminals and service stations in the USA and certain chemicals activities. These included the Verdugt acid salts business; its interest in an olefins cracker at Wilton in the UK; the Plaskon electronics materials business located in the USA and Singapore; the US Fibers and Yarns business; and the sale and leaseback of US railcars. In addition the Group incurred a loss on the closure of its paraxylene joint venture in Singapore. In 1998, the major disposals were exploration and production properties in the USA and Papua New Guinea, the refinery in Lima, Ohio, the sale and leaseback of the Amoco building in Chicago, the retail network in the Czech Republic, the Adibis fuel additives business and a speciality chemicals distribution business. F - 26
NOTES TO FINANCIAL STATEMENTS (Continued) Note 18 -- Disposals (concluded) Total proceeds received for disposals represent the following amounts shown in the cash flow statement: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Proceeds from the sale of businesses................. 8,333 1,292 780 Proceeds from the sale of fixed assets............... 3,029 1,149 1,387 ------ ------ ------ 11,362 2,441 2,167 ====== ====== ====== </TABLE> The disposals comprise the following: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Intangible assets.................................... 458 199 151 Tangible assets...................................... 3,224 2,340 945 Fixed asset-- investments............................ 673 206 157 Net assets of operations held for sale............... 5,290 -- -- Current assets less current liabilities.............. 919 175 88 Other ............................................... 631 (94) (125) ------ ------ ------ 11,195 2,826 1,216 Profit (loss) on sale of businesses.................. 132 321 310 Profit (loss) on sale of fixed assets................ 64 (700) 653 ------ ------ ------ Total consideration.................................. 11,391 2,447 2,179 Deferred consideration............................... (102) (12) (9) Cash................................................. 73 6 (3) ------ ------ ------ Net cash inflow...................................... 11,362 2,441 2,167 ====== ====== ====== </TABLE> F - 27
NOTES TO FINANCIAL STATEMENTS (Continued) Note 19 -- Intangible assets <TABLE> <CAPTION> Exploration Other expenditure Goodwill intangibles Total ----------- ----------- ----------- --------- ($ million) <S> <C> <C> <C> <C> Cost At January 1, 2000..................... 3,780 151 507 4,438 Exchange adjustments................... (62) (9) (5) (76) Acquisitions........................... 2,549 11,669 -- 14,218 Additions.............................. 1,295 -- 53 1,348 Transfers.............................. (813) 246 216 (351) Deletions.............................. (643) (2) (16) (661) ------ ------ ------ ------ At December 31, 2000................... 6,106 12,055 755 18,916 ====== ====== ====== ====== Depreciation At January 1, 2000..................... 728 80 286 1,094 Exchange adjustments................... (14) (5) (3) (22) Charge for the year.................... 264 754 57 1,075 Transfers.............................. (91) 53 117 79 Deletions.............................. (197) -- (6) (203) ------ ------ ------ ------ At December 31, 2000................... 690 882 451 2,023 ====== ====== ====== ====== Net book amount At December 31, 2000................... 5,416 11,173 304 16,893 At December 31, 1999................... 3,052 71 221 3,344 ====== ====== ====== ====== </TABLE> F - 28
NOTES TO FINANCIAL STATEMENTS (Continued) Note 20 -- Tangible assets Property, plant and equipment: <TABLE> <CAPTION> Other of which Exploration Gas Refining businesses Assets and and and and under Production Power Marketing Chemicals corporate Total construction ----------- ----- --------- --------- ---------- ----- ------------ ($ million) <S> <C> <C> <C> <C> <C> <C> <C> Cost At January 1, 2000......... 83,306 45 19,031 14,047 1,716 118,145 3,029 Exchange adjustments....... (2,458) (2) (602) (494) (48) (3,604) (65) Acquisitions............... 14,753 152 6,608 16 239 21,768 374 Additions.................. 4,935 309 1,883 1,286 289 8,702 6,207 Transfers.................. 146 (16) 6,854 102 142 7,228 (3,036) Deletions.................. (7,657) -- (2,162) (59) (354) (10,232) (70) ------ ------ ------ ------ ------ ------- ------ At December 31, 2000....... 93,025 488 31,612 14,898 1,984 142,007 6,439 ====== ====== ====== ====== ====== ======= ====== Depreciation At January 1, 2000......... 48,864 13 9,476 6,267 894 65,514 Exchange adjustments....... (1,689) -- (267) (213) (26) (2,195) Charge for the year........ 4,470 3 1,322 513 78 6,386 Transfers.................. 91 -- 3,928 14 104 4,137 Deletions.................. (5,462) -- (1,316) (43) (187) (7,008) ------ ------ ------ ------ ------ ------- At December 31, 2000....... 46,274 16 13,143 6,538 863 66,834 ====== ====== ====== ====== ====== ======= Net book amount At December 31, 2000....... 46,751 472 18,469 8,360 1,121 75,173 6,439 At December 31, 1999....... 34,442 32 9,555 7,780 822 52,631 3,029 ====== ====== ====== ====== ====== ======= ====== </TABLE> Assets held under capital leases, capitalized interest and land at net book amount included above: <TABLE> <CAPTION> Leased assets Capitalized interest ---------------------------- ---------------------------- Cost Depreciation Net Cost Depreciation Net ----- ------------- ----- ----- ------------ ----- ($ million) ($ million) <S> <C> <C> <C> <C> <C> <C> At December 31, 2000....... 1,926 1,076 850 2,705 1,472 1,233 At December 31, 1999....... 1,741 969 772 2,554 1,321 1,233 ====== ====== ====== ====== ====== ====== </TABLE> <TABLE> <CAPTION> Leasehold land -------------------- Over 50 years Freehold land unexpired Other ------------- ------------- ----- ($ million) <S> <C> <C> <C> At December 31, 2000.................................. 2,012 315 151 At December 31, 1999.................................. 942 47 38 ====== ====== ====== </TABLE> F - 29
NOTES TO FINANCIAL STATEMENTS (Continued) Note 21 -- Fixed assets -- investments <TABLE> <CAPTION> Associated undertakings ------------------------- Share of retained Joint Own Listed Shares Loans profit ventures Loans shares(a) investments(b) Other(c) Total ------ ----- -------- -------- ----- ------ ----------- ----- ----- ($ million) <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Cost At January 1, 2000.... 2,866 882 863 5,204 96 456 -- 51 10,418 Exchange adjustments.. (41) (10) (58) (96) (15) (34) (34) (4) (292) Additions and net movements in joint ventures...... 643 40 161 587 85 64 994 121 2,695 Acquisitions.......... 266 676 -- 1,354 317 -- 666 806 4,085 Transfers............. (68) (23) 176 (4,165) 55 -- -- 130 (3,895) Deletions............. (470) (37) 13 -- (62) (126) (61) (10) (753) ------ ------ ------ ------ ------ ------ ------ ------ ------ At December 31, 2000.. 3,196 1,528 1,155 2,884 476 360 1,565 1,094 12,258 ====== ====== ====== ====== ====== ====== ====== ====== ====== Amounts provided At January 1, 2000.... 277 -- -- -- 31 -- -- 1 309 Exchange adjustments.. (1) (5) -- -- -- -- -- -- (6) Provided in the year.. 6 181 -- -- 28 -- -- 37 252 Transfers............. -- 30 -- -- -- -- -- -- 30 Deletions............. (64) -- -- -- (16) -- -- -- (80) ------ ------ ------ ------ ------ ------ ------ ------ ------ At December 31, 2000.. 218 206 -- -- 43 -- -- 38 505 ====== ====== ====== ====== ====== ====== ====== ====== ====== Net book amount At December 31, 2000.. 2,978 1,322 1,155 2,884 433 360 1,565 1,056 11,753 At December 31, 1999.. 2,589 882 863 5,204 65 456 -- 50 10,109 ====== ====== ====== ====== ====== ====== ====== ====== ====== </TABLE> - ---------- (a) Own shares are held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the Employee Share Schemes (see Note 33) and prior to award under the Long Term Performance Plan (see Note 34). At December 31, 2000 the ESOPs held 45,515,000 (53,989,000 at December 31, 1999) shares for the Employee Share Schemes and 9,507,000 (9,502,000 at December 31, 1999) shares for the Long Term Performance Plan. The market value of these shares at December 31, 2000 was $443 million ($640 million at December 31, 1999). (b) The market value of listed investments at December 31, 2000 was $1,393 million. (c) Other investments are unlisted. Note 22 -- Inventories <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Petroleum................................................... 6,933 3,517 Chemicals................................................... 1,046 828 Other....................................................... 504 202 ------ ------ 8,483 4,547 Stores...................................................... 751 577 ------ ------ 9,234 5,124 ====== ====== Replacement cost............................................ 9,392 5,165 ====== ====== </TABLE> F - 30
NOTES TO FINANCIAL STATEMENTS (Continued) Note 23 -- Receivables <TABLE> <CAPTION> December 31, 2000 December 31, 1999 ----------------- ----------------- Within After Within After 1 year 1 year 1 year 1 year ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Trade receivables.................................. 17,813 -- 9,417 -- ====== ====== ====== ====== Other receivables: Joint ventures................................... 582 -- 725 -- Associated undertakings.......................... 98 46 60 45 Prepayments and accrued income................... 2,137 486 1,229 459 Taxation recoverable............................. 412 -- 263 83 Pension prepayment............................... -- 3,609 -- 2,541 Other............................................ 2,766 469 1,653 327 ------ ------ ------ ------ 5,995 4,610 3,930 3,455 ====== ====== ====== ====== </TABLE> Provisions for doubtful debts deducted from Trade receivables amounted to $357 million ($117 million at December 31, 1999). - ---------- See Note 43 -- US generally accepted accounting principles. Note 24 -- Current assets -- investments <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Publicly traded -- United Kingdom...................................... 59 56 -- Foreign............................................. 220 42 ------ ------ 279 98 Not publicly traded..................................................... 382 122 ------ ------ 661 220 ====== ====== Stock exchange value of publicly traded investments..................... 280 99 ====== ====== </TABLE> Note 25 -- Finance debt <TABLE> <CAPTION> December 31, 2000 December 31, 1999 ----------------- ----------------- Within After Within After 1 year 1 year 1 year 1 year ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Bank loans and overdrafts.......................... 895(a) 1,035 264(a) 726 Other loans........................................ 5,420(a) 11,916 4,548(a) 7,181 ------ ------ ------ ------ Total borrowings................................... 6,315 12,951 4,812 7,907 Obligations under capital leases................... 103 1,821 88 1,737 ------ ------ ------ ------ 6,418 14,772 4,900 9,644 ====== ====== ====== ====== </TABLE> - --------------- (a) Amounts due within one year include current maturities of long-term debt. F - 31
NOTES TO FINANCIAL STATEMENTS (Continued) Note 25 -- Finance debt (continued) Where a borrowing is swapped into another currency, the borrowing is accounted in the swap currency and not in the original currency of denomination. Total borrowings include $369 million ($191 million at December 31, 1999) for the carrying value of currency swaps and forward contracts. Included within Other loans repayable within one year are US Industrial Revenue/Municipal Bonds of $1,671 million (December 31, 1999 $1,376 million) with maturity periods ranging up to 34 years. They are classified as repayable within one year, as required under UK GAAP, as the bondholders typically have the option to tender these bonds for repayment on interest reset dates. Any bonds that are tendered are usually remarketed and BP has not experienced any significant repurchases. BP considers these bonds to represent long-term funding when assessing the maturity profile of its borrowings. Analysis of borrowings by year of repayment <TABLE> <CAPTION> December 31, 2000 December 31, 1999 ------------------------------- ------------------------------ Bank loans Bank loans and Other and Other overdrafts loans Total overdrafts loans Total --------- --------- --------- ---------- -------- --------- ($ million) <S> <C> <C> <C> <C> <C> <C> Due after 10 years........ 258 3,296 3,554 110 1,290 1,400 Due within 6-10 years...... 26 3,402 3,428 45 1,816 1,861 5 years......... 24 1,202 1,226 410 722 1,132 4 years......... 417 744 1,161 36 377 413 3 years......... 75 1,187 1,262 87 1,774 1,861 2 years......... 235 2,085 2,320 38 1,202 1,240 --------- --------- --------- --------- --------- --------- 1,035 11,916 12,951 726 7,181 7,907 1 year.......... 895 5,420 6,315 264 4,548 4,812 --------- --------- --------- --------- --------- --------- 1,930 17,336 19,266 990 11,729 12,719 ========= ========= ========= ========= ========= ========= </TABLE> Amounts included above repayable by instalments part of which falls due after five years from December 31, are as follows: <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> After five years............................................ 27 46 Within five years........................................... 216 91 ------ ------ 243 137 ====== ====== </TABLE> Interest rates on borrowings repayable wholly or partly more than five years from December 31, 2000 range from 4% to 10% with a weighted average of 7%. The weighted average interest rate on finance debt is 7%. At December 31, 2000 the Group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $3,450 million ($3,000 million at December 31, 1999) expiring in 2001. These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates. Certain of these facilities support the Group's commercial paper programme. F - 32
NOTES TO FINANCIAL STATEMENTS (Continued) Note 25 -- Finance debt (continued) Analysis of borrowings by currency <TABLE> <CAPTION> December 31, December 31, 2000 1999 ----------------------------------------------------------------- ----------- Fixed rate debt Floating rate debt -------------------------------- ------------------- Weighted Weighted Weighted average average time average interest for which interest rate rate is fixed Amount rate Amount Total Total -------- ------------- ------ -------- ------ ----- ----- (%) (Years) ($ million) (%) ($ million)($ million) ($ million) <S> <C> <C> <C> <C> <C> <C> <C> US dollars............ 7 9 10,199 6 8,326 18,525 12,444 Sterling.............. -- -- -- 6 449 449 49 Other currencies...... 8 30 45 10 247 292 226 -------- -------- ------- ------- Total loans........... 10,244 9,022 19,266 12,719 ======== ======== ======= ======= </TABLE> The Group aims for a balance between floating and fixed interest rates and, in 2000, the Group's upper limit for the proportion of floating rate debt was 65% of total net debt outstanding. Aside from debt issued in the US municipal bond markets, interest rates on floating rate debt denominated in US dollars are linked principally to LIBOR, while rates on debt in other currencies are based on local market equivalents. The Group monitors interest rate risk using a process of sensitivity analysis. Assuming no changes to the borrowings and hedges described above, it is estimated that a change of 1% in the general level of interest rates on January 1, 2001 would change 2001 profit before tax by approximately $110 million. Fair values and carrying amounts of borrowings <TABLE> <CAPTION> December 31, ---------------------------------------------- 2000 1999 ---------------------- ---------------------- Carrying Carrying Fair value amount Fair value amount ---------- -------- ---------- -------- ($ million) <S> <C> <C> <C> <C> Short-term borrowings.................... 3,706 3,706 2,433 2,433 Long-term borrowings..................... 15,573 15,299 9,979 10,118 --------- --------- --------- --------- Total borrowings......................... 19,279 19,005 12,412 12,551 ========= ========= ========= ========= </TABLE> The fair value and carrying amounts of borrowings shown above exclude the effects of currency swaps, interest rate swaps and forward contracts (which are included for presentation in the balance sheet). Long-term borrowings include debt which matures in the year from December 31, 2000, whereas in the balance sheet long-term debt of current maturity is reported under amounts falling due within one year. Long-term borrowings also include US Industrial Revenue/Municipal Bonds classified on the balance sheet as repayable within one year. The carrying amount of the Group's short-term borrowings, which mainly comprise commercial paper, bank loans and overdrafts, approximate their fair value. The fair value of the Group's long-term borrowings is estimated using quoted prices or, where these are not available, discounted cash flow analyses, based on the Group's current incremental borrowing rates for similar types and maturities of borrowing. F - 33
NOTES TO FINANCIAL STATEMENTS (Continued) Note 25 -- Finance debt (continued) Obligations under capital leases The future minimum lease payments together with the present value of the net minimum lease payments were as follows: <TABLE> <CAPTION> December 31, 2000 ------------- ($ million) <S> <C> 2001 ............................................................... 136 2002 ............................................................... 193 2003 ............................................................... 181 2004 ............................................................... 187 2005 ............................................................... 194 Thereafter........................................................... 3,371 ----------- 4,262 Less: amount representing lease interest............................. 2,338 ----------- Present value of net minimum capital lease payments.................. 1,924 =========== of which -- due within one year...................................... 103 -- due after one year....................................... 1,821 ----------- </TABLE> The following information is presented in compliance with the requirements of US GAAP. Bank loans and overdrafts and other loans-- long term <TABLE> <CAPTION> Weighted average December 31, interest rate at --------------- December 31, 2000 2000 1999 ----------------- ------ ------ (%) ($ million) <S> <C> <C> <C> US dollars................................ 7 12,599 7,786 Sterling.................................. 7 289 40 Other currencies.......................... 9 63 81 ------ ----- 12,951 7,907 ====== ===== </TABLE> Bank loans and overdrafts and other loans-- short term <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Current maturities of long-term debt........................ 938 1,003 Commercial paper............................................ 2,943 2,201 Bank loans and overdrafts................................... 762 232 Other....................................................... 1,672 1,376 ------ ------ 6,315 4,812 ====== ====== </TABLE> F - 34
NOTES TO FINANCIAL STATEMENTS (Continued) Note 25 -- Finance debt (concluded) <TABLE> <CAPTION> Weighted average interest rate at December 31, ---------------- 2000 1999 ------ ------ (%) <S> <C> <C> (%) Commercial paper............................................ 7 6 Bank loans, overdrafts and other borrowings................. 8 6 US Industrial Revenue/Municipal bonds....................... 5 5 </TABLE> Note 26 -- Accounts payable and accrued liabilities <TABLE> <CAPTION> December 31, 2000 December 31, 1999 ----------------- ----------------- Within After Within After 1 year 1 year 1 year 1 year ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Trade payables..................................... 14,363 -- 8,203 -- ====== ====== ====== ====== Other accounts payable and accrued liabilities: Joint ventures................................... -- -- 278 -- Associated undertakings.......................... 296 4 199 4 Production taxes................................. 347 1,123 417 1,140 Taxation on profits.............................. 3,192 2 2,558 39 Social security.................................. 59 -- 14 -- Accruals and deferred income..................... 6,557 1,876 3,610 618 Dividends........................................ 1,178 -- 971 -- Other............................................ 4,737 2,218 2,125 444 ------ ------ ------ ------ 16,366 5,223 10,172 2,245 ====== ====== ====== ====== </TABLE> Note 27 -- Other provisions <TABLE> <CAPTION> Unfunded Other pension postretirement Decommissioning Environmental plans benefits Other Total --------------- ------------- ------- -------------- ----- ----- ($ million) <S> <C> <C> <C> <C> <C> <C> At January 1, 2000...... 2,785 917 1,595 2,244 731 8,272 Exchange adjustments.... (133) (10) (108) -- (37) (288) Acquisitions............ 484 1,222 125 579 844 3,254 New provisions.......... 139 228 174 62 238 841 Unwinding of discount... 110 55 -- -- 24 189 Utilized/deleted........ (384) (281) (207) (159) (264) (1,295) ------ ------ ------ ------ ------ ------ At December 31, 2000.... 3,001 2,131 1,579 2,726 1,536 10,973 ====== ====== ====== ====== ====== ====== </TABLE> F - 35
NOTES TO FINANCIAL STATEMENTS (Continued) Note 27 -- Other provisions (concluded) At December 31, 2000 the provision for the costs of decommissioning the Group's oil and natural gas production facilities and pipelines at the end of their economic lives was $3,001 million ($2,785 million at December 31, 1999). These costs are expected to be incurred over the next 30 years. The provision has been estimated using existing technology, at current prices and discounted using a real discount rate of 3.5% (1999 3.5%). The provision for environmental liabilities at December 31, 2000 was $2,131 million ($917 million at December 31, 1999). This represents primarily the estimated environmental restoration and remediation costs for closed sites or facilities that have been sold. These costs are expected to be incurred over the next 10 years. The provision has been estimated using existing technology, at current prices, and discounted using a real discount rate of 3.5% (1999 3.5%). The Group also holds provisions for potential future awards under the long-term performance plan, expected rental shortfalls on surplus properties and sundry other liabilities. To the extent that these liabilities are not expected to be settled within the next three years, the provisions are discounted using a real discount rate of 3.5% (1999 3.5%). Note 28 -- Derivative financial instruments An outline of the Group's major financial risks and the policies and objectives pursued in relation to these risks is set out in the financial risk management section of Item 5 -- Operating and Financial Review and Prospects and in Item 11 -- Quantitative and Qualitative Disclosures about Market Risk. In the normal course of business the Group is a party to derivative financial instruments (derivatives) with off-balance sheet risk, primarily to manage its exposure to fluctuations in foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt. The Group also manages certain of its exposures to movements in oil and natural gas prices. The underlying economic currency of the Group's cash flows is mainly the US dollar. Accordingly, most of our borrowings are in US dollars, are hedged with respect to the US dollar or swapped into dollars where this achieves a lower cost of financing. Significant non-dollar cash flow exposures are hedged. Gains and losses arising on these hedges are deferred and recognized in the income statement or as adjustments to carrying amounts, as appropriate, only when the hedged item occurs. In addition, we trade derivatives in conjunction with these risk management activities. The results of trading are recognized in income in the current period. These derivatives involve, to varying degrees, credit and market risk. With regard to credit risk, the Group may be exposed to loss in the event of non-performance by a counterparty. The Group controls credit risk by entering into derivative contracts only with highly credit-rated counterparties and through credit approvals, limits and monitoring procedures and does not usually require collateral or other security. The Group has not experienced material non-performance by any counterparty. Market risk is the possibility that a change in interest rates, currency exchange rates or oil and natural gas prices will cause the value of a financial instrument to decrease or its obligations to become more costly to settle. When derivatives are used for the purpose of risk management they do not expose the Group to market risk because the exposure to market risk created by the derivative is offset by the opposite exposure arising from the asset, liability, cash flow or transaction being hedged. When derivatives are held for trading purposes, the exposure of the Group to market risk is represented by potential changes in their fair (market) values. The measurement of market risk in trading activities is discussed further below. F - 36
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) With the exception of the table of currency exposures shown on page F-39, short-term debtors and creditors which arise directly from the Group's operations have been excluded from the disclosures contained in this note, as permitted by FRS No. 13 'Derivatives and Other Financial Instruments: Disclosures'. Interest rate risk The interest rate and currency profile of the financial liabilities of the Group at December 31, 2000, after taking into account the effect of interest rate swaps, currency swaps and forward contracts, are set out below. <TABLE> <CAPTION> December 31, 1999 ------------------------------------------------------------------------------------- Fixed rate Floating rate Interest free ------------------------------------ ----------------- --------------------- Weighted Weighted Weighted Weighted average average time average average time interest for which interest until rate rate is fixed Amount rate Amount maturity Amount Total ------------- ------------- ------ -------- ------ ------------ ------ ------ (%) (Years) ($m) (%) ($m) (Years) ($m) ($m) <S> <C> <C> <C> <C> <C> <C> <C> <C> At December 31, 2000 US dollars.......... 7 9 10,506 6 10,674 4 2,155 23,335 Sterling............ -- -- -- 6 449 6 147 596 Other currencies.... 8 30 45 10 247 2 532 824 ------- ------- ------- ------- 10,551 11,370 2,834 24,755 ======= ======= ======= ======= At December 31, 1999 US dollars.......... 7 9 6,704 5 7,587 7 912 15,203 Sterling............ -- -- -- 6 49 4 217 266 Other currencies.... 8 31 46 6 180 5 319 545 ------- ------- ------- ------- 6,750 7,816 1,448 16,014 ======= ======= ======= ======= </TABLE> <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Analysis of the above liabilities by balance sheet caption: Creditors-- amounts falling due within one year - --Finance debt.................................................... 6,418 4,900 Creditors-- amounts falling due after more than one year - --Finance debt.................................................... 14,772 9,644 - --Other creditors................................................. 2,501 1,062 Provisions for liabilities and charges - --Other provisions................................................ 1,064 408 ------- ------- 24,755 16,014 ======= ======= </TABLE> F - 37
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) The financial liabilities upon which interest is paid comprise principally borrowings and net obligations under finance leases. In managing its finance debt, the Group aims for a balance between floating and fixed interest rates and, in 2000, the Group's upper limit for the proportion of floating rate debt was 65% of total net debt outstanding. Interest rate swaps are used by the Group to modify the interest characteristics of its long-term borrowings from a fixed to a floating rate basis or vice versa. The following table indicates the types of swaps used and their weighted average interest rates. <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million except percentages) <S> <C> <C> Receive fixed rate swaps-- notional amount 2,310 2,300 Average receive fixed rate ......... 6.4% 6.3% Average pay floating rate........... 6.7% 5.9% Pay fixed rate swaps-- notional amount 3,125 3,221 Average pay fixed rate.............. 6.7% 7.1% Average receive floating rate....... 6.7% 6.0% </TABLE> The financial liabilities which are interest-free comprise various accruals, sundry creditors and provisions relating to the Group's normal commercial operations with payment dates spread over a number of years. The following table shows the interest rate and currency profile of the Group's material financial assets. <TABLE> <CAPTION> Fixed rate Floating rate Interest free ------------------------------------ ----------------- --------------------- Weighted Weighted Weighted Weighted average average time average average time interest for which interest until rate rate is fixed Amount rate Amount maturity Amount Total ------------- ------------- ------ -------- ------ ------------ ------ ------ (%) (Years) ($m) (%) ($m) (Years) ($m) ($m) <S> <C> <C> <C> <C> <C> <C> <C> <C> At December 31, 2000 US dollars.......... 4 1 226 5 1,127 2 1,502 2,855 Sterling............ 8 2 81 5 74 2 803 958 Other currencies.... 6 1 115 6 593 3 942 1,650 ------- ------- ------- ------- 422 1,794 3,247 5,463 ======= ======= ======= ======= At December 31, 1999 US dollars.......... 5 1 12 5 748 3 237 997 Sterling............ 9 2 55 -- -- 1 357 412 Other currencies.... 6 1 44 3 168 2 371 583 ------- ------- ------- ------- 111 916 965 1,992 ======= ======= ======= ======= </TABLE> <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Analysis of the above assets by balance sheet caption: Fixed assets-- investments....................................... 3,054 115 Current assets - --Debtors-- amount falling due after more than one year........... 578 326 - --Investments..................................................... 661 220 - --Cash at bank and in hand........................................ 1,170 1,331 ------- ------- 5,463 1,992 ======= ======= </TABLE> The floating rate financial assets earn interest at various rates set principally with respect to LIBOR or the local market equivalent. Fixed asset investments included in the table above are held for the long-term and have no maturity period. They are excluded from the calculation of weighted average time until maturity. F - 38
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) Maturity profile of financial liabilities The profile of the maturity of the financial liabilities included in the Group's balance sheet is shown in the table below. <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Due within: 1 year................................... 6,418 4,900 1 to 2 years............................. 3,834 1,505 2 to 5 years............................. 4,456 3,845 Thereafter............................... 10,047 5,764 ------ ------ 24,755 16,014 ====== ====== </TABLE> Foreign exchange rate risk The table below shows the Group's principal currency exposures arising from normal trading activities. These exposures give rise to net currency gains and losses recognized in the profit and loss account. Such exposures comprise the monetary assets and monetary liabilities of the Group that are not denominated in the functional currency of the operating unit involved, other than certain non-US dollar borrowings treated as hedges of net investments in overseas operations. As at December 31, these exposures were as shown below. Functional currency of Group operation <TABLE> <CAPTION> Net foreign currency monetary assets (liabilities) ------------------------------------------------- US dollar Sterling Euro Other Total --------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> At December 31, 2000 US dollar.............................. -- (555) 313 (534) (776) Sterling............................... 487 -- 498 269 1,254 Other.................................. 584 189 (9) (231) 533 -------- -------- -------- -------- -------- Total 1,071 (366) 802 (496) 1,011 ======== ======== ======== ======== ======== At December 31, 1999 US dollar.............................. -- 747 460 (385) 822 Sterling............................... 141 -- 264 (19) 386 Other.................................. 205 (114) 1 26 118 -------- -------- -------- -------- -------- Total 346 633 725 (378) 1,326 ======== ======== ======== ======== ======== </TABLE> In accordance with its policy for managing its foreign exchange rate risk, the Group enters into various types of foreign exchange contracts, such as currency swaps, forwards and options. The fair values and carrying amounts of these derivatives are shown in the fair value disclosures below. F - 39
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) Fair values of financial assets and liabilities The estimated fair value of the Group's financial instruments is shown in the table below. The table also shows the `net carrying amount' of the financial asset or liability. This amount represents the net book value, i.e. market value when acquired or later marked to market. The carrying amounts and fair values of finance debt shown below exclude the effects of interest rate swaps, currency swaps and forward contracts (which are included for presentation in the balance sheet). Current maturities of long-term finance debt are included under long-term borrowings. <TABLE> <CAPTION> December 31, ------------------------------------------------------------------------------- 2000 1999 ------------------------------------- ------------------------------------- Net carrying Net carrying Net fair value amount Net fair value amount asset (liability) asset (liability) asset (liability) asset (liability) ---------------- ---------------- ---------------- ---------------- ($ million) <S> <C> <C> <C> <C> Primary financial instruments Fixed assets--investments..................... 2,882 3,054 115 115 Current assets - --Debtors--amounts falling due after more than one year.................. 578 578 326 326 - --Investments.................................. 662 661 221 220 - --Cash at bank and in hand..................... 1,170 1,170 1,331 1,331 Finance debt - --Short-term borrowings........................ (3,706) (3,706) (2,433) (2,433) - --Long-term borrowings......................... (15,573) (15,299) (9,979) (10,118) - --Net obligations under finance leases.......... (1,831) (1,816) (1,824) (1,802) Creditors--amounts falling due after more than one year - --Other creditors............................... (2,501) (2,501) (1,062) (1,062) Provisions for liabilities and charges--Other provisions..................... (1,064) (1,064) (408) (408) Derivative financial or commodity instruments Risk management -- interest rate contracts..... (49) -- 37 -- -- foreign exchange contracts. (338) (369) (209) (191) -- oil price contracts........ 4 4 -- -- -- natural gas price contracts 31 12 2 -- Trading -- interest rate contracts.... -- -- -- -- -- foreign exchange contracts. -- -- -- -- -- oil price contracts........ 36 36 (61) (61) -- natural gas price contracts 24 24 -- -- </TABLE> F - 40
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) Interest rate contracts include futures contracts, swap agreements and options. Foreign exchange contracts include forward and futures contracts, swap agreements and options. Oil and natural gas price contracts are those which require settlement in cash and include futures contracts, swap agreements and options and cash-settled commodity instruments (derivative commodity contracts that permit settlement either by delivery of the underlying commodity or in cash) such as forward contracts. The following methods and assumptions were used by the Group in estimating its fair value disclosures for its financial instruments: Fixed assets - Investments: The carrying amount reported in the balance sheet for unlisted fixed asset investments approximates their fair value. The fair value of listed fixed asset investments has been determined by reference to market prices. Current assets - Debtors - amounts falling due after more than one year: The fair value of other debtors due after one year is estimated not to be materially different from its carrying value. Current assets - Investments and Cash at bank and in hand: The carrying amount reported in the balance sheet for unlisted current asset investments and cash at bank and in hand approximates their fair value. The fair value of listed current asset investments has been determined by reference to market prices. Finance debt: The carrying amount of the Group's short-term borrowings, which mainly comprise commercial paper, bank loans and overdrafts, approximates their fair value. The fair value of the Group's long-term borrowings and finance lease obligations is estimated using quoted prices or, where these are not available, discounted cash flow analyses, based on the Group's current incremental borrowing rates for similar types and maturities of borrowing. Creditors - amounts falling due after more than one year - Other creditors: These liabilities are predominantly interest-free. In view of the short maturities, the reported carrying amount is estimated to approximate the fair value. Provisions for liabilities and charges - Other provisions: Where the liability will not be settled for a number of years the amount recognized is the present value of the estimated future expenditure. The carrying amount of provisions for onerous contracts thus approximates the fair value. Derivative financial or commodity instruments: The fair values of the Group's interest rate contracts (swaps) are based on pricing models which take into account relevant market data. Fair values for the Group's foreign exchange contracts (forward contracts, swap agreements and options) are based on market prices of comparable instruments. The fair values of the Group's oil and natural gas price contracts (futures contracts, swap agreements, options and forward contracts) are based on market prices. Risk management Gains and losses on derivatives used for risk management purposes are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. When an anticipated transaction is no longer likely to occur or finance debt is terminated before maturity, any deferred gain or loss that has arisen on the related derivative is recognized in the income statement, together with any gain or loss on the terminated item. Where such derivatives used for hedging purposes are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis which matches the timing and accounting treatment of the underlying hedged item. The unrecognized and carried-forward gains and losses on derivatives used for hedging, and the movements therein, are shown in the following table. F - 41
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) <TABLE> <CAPTION> Unrecognized Carried forward in the balance sheet ----------------------- ------------------------------------ Gains Losses Total Gains Losses Total ----- ------ ----- ----- ------ ----- ($ million) <S> <C> <C> <C> <C> <C> <C> Gains and losses at January 1, 2000............ 236 (215) 21 65 (283) (218) of which accounted for in income in 2000..... 54 (60) (6) 32 (45) (13) Gains and losses at December 31, 2000.......... 303 (302) 1 56 (443) (387) of which expected to be recognized in income: In 2001...................................... 216 (140) 76 20 (194) (174) In 2002 or later............................. 87 (162) (75) 36 (249) (213) Gains and losses at January 1, 1999............ 253 (402) (149) 143 (194) (51) of which accounted for in income in 1999..... 115 (95) 20 58 (66) (8) </TABLE> Trading activities The Group maintains active trading positions in a variety of derivatives. This activity is undertaken in conjunction with risk management activities. Derivatives held for trading purposes are marked to market and any gain or loss recognized in the income statement. For traded derivatives, many positions have been neutralized, with trading initiatives being concluded by taking opposite positions to fix a gain or loss, thereby achieving a zero net market risk. The following table shows the fair value at the year end and the average net fair value of derivatives and other financial instruments held for trading purposes during the year. <TABLE> <CAPTION> Years ended December 31, ----------------------------------------------------------------------------- 2000 1999 ------------------------------------- ------------------------------------- Year end Average Average fair Year end net fair Year end Year end net fair value fair value value asset value fair value value asset asset liability (liability) asset liability (liability) -------- ---------- ----------- ------- ---------- ----------- ($ million) <S> <C> <C> <C> <C> <C> <C> Interest rate contracts........ -- -- -- -- -- -- Foreign exchange contracts..... 10 (10) (3) 4 (4) -- Oil price contracts............ 159 (123) 4 155 (216) 54 Natural gas price contracts.... 1,288 (1,264) 15 -- -- -- -------- -------- -------- -------- -------- -------- 1,457 (1,397) 16 159 (220) 54 ======== ======== ======== ======== ======== ======== </TABLE> The Group measures its market risk exposure, i.e. potential gain or loss in fair values, on its trading activity using a value at risk technique. This technique is based on a variance/covariance model and makes 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 12 months, together with the correlation of these price movements. The potential movement in fair values is expressed to three standard deviations which is 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 Group 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 model takes account of derivative financial instruments such as interest rate forward and futures contracts, swap agreements, options and swaptions, foreign exchange forward and futures contracts, swap agreements and options and oil price futures, swap agreements and options. Financial assets and liabilities and physical crude oil and refined products that are treated as trading positions are also included in these calculations. The value at risk calculation for oil 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. F - 42
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) The following table shows values at risk for trading activities. <TABLE> <CAPTION> Years ended December 31, ---------------------------------------------------------------------------------- 2000 1999 ------------------------------------- ------------------------------------- High Low Average Year end High Low Average Year end ----- ----- ------- -------- ----- ----- ------- -------- ($ million) <S> <C> <C> <C> <C> <C> <C> <C> <C> Interest rate trading................ 2 -- 1 -- 1 -- 1 -- Foreign exchange trading............. 15 -- 1 1 13 -- 3 1 Oil price trading.................... 23 4 13 13 15 5 9 10 Natural gas price trading............ 16 1 6 13 -- -- -- -- </TABLE> The presentation of trading results shown below includes certain activities of the Group's oil trading division which involve the use of derivative financial instruments in conjunction with physical and paper trading of oil. It is considered that a more comprehensive representation of the Group's oil trading activities is given by the classification of the gains or losses on such derivatives along with those arising from the physical and paper trades to which they relate. The following table shows the trading income arising from derivatives and other financial instruments. For oil price contract trading, this also includes income or losses arising on trading of derivative commodity instruments and physical oil trades, representing the net result of the oil-trading portfolio. <TABLE> <CAPTION> Year ended December 31, ------------------------ 2000 1999 -------- -------- Net gain Net gain (loss) (loss) -------- -------- ($ million) <S> <C> <C> Oil price derivative financial and commodity instruments............. 77 133 Physical oil trades.................................................. 434 151 ------ ------ Total oil trading.................................................... 511 284 Interest rate trading................................................ 1 -- Foreign exchange trading............................................. 52 23 Natural gas price trading............................................ 17 -- ------ ------ 581 307 ====== ====== </TABLE> The following information is presented in compliance with the requirements of US GAAP. Further information on accounting policies The following information is presented in amplification of the accounting policies presented in Note 1 -- Accounting policies. Reporting in the income statement Gains and losses on oil price contracts held for trading and for risk management purposes are reported in cost of sales in the income statement in the period in which the change in value occurs. Gains and losses on interest rate or foreign currency derivatives used for trading are reported in other income and cost of sales, respectively. Gains and losses in respect of derivatives used to manage interest rate exposures are recognized as adjustments to interest expense. Where derivatives are used to convert non-US dollar borrowing into US dollars, the gains and losses are deferred and recognized on maturity of the underlying debt, together with the matching loss or gain on the debt. The two amounts offset each other in the income statement. F - 43
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) Gains and losses on derivatives identified as hedges of significant non-US dollar firm commitments or anticipated transactions are not recognized until the hedged transaction occurs. The treatment of the gain or loss arising on the designated derivative reflects the nature and accounting treatment of the hedged item. The gain or loss is recorded in cost of sales in the income statement or as an adjustment to carrying values in the balance sheet, as appropriate. Gains and losses arising from natural gas price derivatives are recognized in earnings when the hedged transaction occurs. The gains or losses are reported as components of the related transactions. Reporting in the balance sheet The carrying amounts of foreign exchange contracts that hedge finance debt are included within finance debt in the balance sheet. The carrying amounts of other derivatives, including option premiums paid or received, are included in the balance sheet under receivables or payables within current assets and current liabilities respectively, as appropriate. Cash flow effects Interest rate swaps give rise, at specified intervals, to cash settlement of interest differentials. Under currency swaps the counterparties initially exchange a principal amount in two currencies, agreeing to re-exchange the currencies at a future date at the same exchange rate. The Group's currency swaps have terms of up to nine years. Interest rate futures require an initial margin payment and daily settlement of margin calls. Interest rate forwards require settlement of the interest rate differential on a specified future date. Currency forwards require purchase or sale of an agreed amount of foreign currency at a specified exchange rate at a specified future date, generally over periods of up to one year for the Group. Currency options involve the initial payment or receipt of a premium and will give rise to delivery of an agreed amount of currency at a specified future date if the option is exercised. For oil and natural gas price futures and options traded on regulated exchanges, BP meets initial margin requirements by bank guarantees and daily margin calls in cash. For swaps and over-the-counter options, BP settles with the counterparty on conclusion of the pricing period. In the statement of cash flows the effect of interest rate derivatives is reflected in interest paid. The effect of foreign currency derivatives used for hedging non-US dollar debt is included under financing. The cash flow effects of foreign currency derivatives used to hedge non-US dollar firm commitments and anticipated transactions are included in net cash inflow from operating activities for items relating to earnings or in capital expenditure or acquisitions, as appropriate, for items of a capital nature. The cash flow effects of all oil and natural gas price derivatives and all traded derivatives are included in net cash inflow from operating activities. Fair value of financial instruments The following information is presented in compliance with the requirements of FASB Statement of Financial Accounting Standards No. 107 -- 'Disclosures about Fair Value of Financial Instruments'. F - 44
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) The carrying amounts and fair values of finance debt are as follows: <TABLE> <CAPTION> December 31, --------------------------------------------- 2000 1999 --------------------- --------------------- Carrying Fair Carrying Fair amount value amount value --------- --------- --------- --------- ($ million) <S> <C> <C> <C> <C> Finance debt Long-term............................... 15,299 15,573 10,118 9,979 Short-term.............................. 3,706 3,706 2,433 2,433 Cash at bank and in hand.................. 1,170 1,170 1,331 1,331 </TABLE> The following information is presented in compliance with the requirements of FASB Statement of Financial Accounting Standards No. 119 -- 'Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments'. The carrying amounts of foreign exchange contracts that hedge finance debt are included within finance debt in the balance sheet. The carrying amounts of other derivatives are included in the balance sheet under receivables or payables as appropriate. In addition to the above financial instruments, the Group has issued third party guarantees and indemnities amounting to $454 million ($458 million at December 31, 1999). The credit risk and maximum cash requirement of these guarantees and indemnities is the full contractual amount, however no material loss is expected to arise. The following information is presented in compliance with the requirements of FASB Statement of Accounting Standards No.105 -- `Disclosure of Information about Financial Instruments with Off-Balance-Sheet Risk and Financial Instruments with Concentrations of Credit Risk'. The table shows the 'fair value' of the asset or liability created by derivatives. This represents the market value at the balance sheet date. Credit exposure at December 31 is represented by the column 'fair value asset'. The table also shows the 'net carrying amount' of the asset or liability created by derivatives. This amount represents the net book value. F - 45
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) <TABLE> <CAPTION> Gross Net carrying contract Fair value Fair value amount asset amount asset (liability) (liability) --------- ---------- ---------- ------------ ($ million) <S> <C> <C> <C> <C> At December 31, 2000 Risk management Interest rate contracts........ 5,435 54 (103) -- Foreign exchange contracts..... 8,132 114 (452) (369) Oil price contracts............ 434 19 (15) 4 Natural gas price contracts.... 2,614 147 (116) 12 Trading Interest rate contracts........ -- -- -- -- Foreign exchange contracts..... 2,434 10 (10) -- Oil price contracts............ 6,316 159 (123) 36 Natural gas price contracts.... 36,206 1,288 (1,264) 24 At December 31, 1999 Risk management Interest rate contracts........ 5,521 138 (101) -- Foreign exchange contracts..... 5,026 39 (248) (191) Oil price contracts............ 504 13 (13) -- Natural gas price contracts.... 4,395 56 (54) -- Trading Interest rate contracts........ 200 -- -- -- Foreign exchange contracts..... 1,674 4 (4) -- Oil price contracts............ 3,144 148 (207) (59) </TABLE> Interest rate contracts include futures contracts, swap agreements and options. Foreign exchange contracts include forward and futures contracts, swap agreements and options. Oil and natural gas price contracts are those which require settlement in cash and include futures contracts, swap agreements and options. Interest rate risk management The Group enters into interest rate contracts to manage its cost of borrowing as indicated in the following table: <TABLE> <CAPTION> December 31, 2000 December 31, 1999 ----------------------------- ----------------------------- Gross Fair Fair Gross Fair Fair contract value value contract value value amount asset liability amount asset liability -------- ------- ------- ------- ------- ------- ($ million) <S> <C> <C> <C> <C> <C> <C> Swaps ....................... 5,435 54 (103) 5,521 138 (101) ======= ======= ======= ======= ======= ======= </TABLE> Interest rate swaps allow BP to modify the interest characteristics of its long-term borrowings from a fixed to a floating rate basis or vice versa. Under interest rate swaps, the Group agrees with other parties to exchange, at specified intervals, the interest differentials calculated by reference to an agreed notional principal amount. There is no exchange of the underlying principal amount. F - 46
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) The following table indicates the types of swaps used and their weighted average interest rates. Average variable rates are based on the actual rates in place at December 31; these may change significantly, affecting future cash flows. Swap contracts mainly have maturities between one and ten years. <TABLE> <CAPTION> December 31, ----------------------------- 2000 1999 --------- --------- ($ million, except percentages) <S> <C> <C> Receive-- fixed swaps-- notional amount............ 2,310 2,300 Average receive fixed rate......................... 6.4% 6.3% Average pay floating rate.......................... 6.7% 5.9% Pay-- fixed swaps-- notional amount................ 3,125 3,221 Average pay fixed rate............................. 6.7% 7.1% Average receive floating rate...................... 6.7% 6.0% </TABLE> Interest rate futures contracts may be used by the Group, on occasion, in preference to interest rate swaps to achieve a more cost effective method of managing the mix between fixed and floating rate debt. These contracts are commitments to either purchase or sell designated financial instruments at a future date for a specified price, and may be settled in cash or through delivery. The Group may hold highly liquid contracts, such as US Treasury bond futures, with terms ranging up to a year. Initial margin requirements and daily calls are met either by the deposit of securities or in cash. Futures contracts have little credit risk as regulated exchanges are the counterparties. Interest rate forward contracts, which include forward rate agreements and options on forward rate agreements, may also be used by the Group to manage interest rate risk on debt. These contracts are agreements which allow the interest rate cost on a principal amount to be fixed for a specified period commencing on a future date. Swaptions may also be employed to manage interest rate risk on debt. A swaption is an agreement that conveys the right, but not the obligation, to swap a series of fixed rate interest payments for floating rate interest payments, or vice versa, at a given future point in time. Typically the swaptions entered into by the Group are cash settled at expiry. Foreign exchange risk management The Group enters into various types of foreign exchange contracts in managing its foreign exchange risk as indicated in the following table: <TABLE> <CAPTION> December 31, 2000 December 31, 1999 ------------------------------- ------------------------------ Gross Fair Fair Gross Fair Fair contract value value contract value value amount asset liability amount asset liability --------- --------- --------- --------- --------- --------- ($ million) <S> <C> <C> <C> <C> <C> <C> Currency swaps............... 2,441 15 (303) 2,109 30 (200) Forwards..................... 5,691 99 (149) 2,237 6 (44) Options...................... -- -- -- 680 3 (4) --------- --------- --------- --------- --------- --------- 8,132 114 (452) 5,026 39 (248) ========= ========= ========= ========= ========= ========= </TABLE> F - 47
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) The Group's foreign exchange management policy is to minimize economic exposures from currency movements against the US dollar. This is achieved by raising finance in US dollars, hedging with respect to the US dollar or swapping into US dollars where this achieves a lower cost of financing, and hedging significant non-dollar cash flows. Examples of significant non-dollar cash flows are sterling-based capital lease payments, sterling tax payments, sterling dividend payments and capital expenditure and operational requirements of Exploration in the UK. Under currency swaps the counterparties initially exchange a principal amount in two currencies, agreeing to re-exchange the currencies at a future date and at the same exchange rate. In addition, interest payments in the respective currencies are exchanged at specified intervals over the term of the agreement. The Group's currency swaps have terms up to nine years. The majority of the Group's currency swaps relate to major currencies such as Sterling, Euros, Swiss Francs, Canadian Dollars and Japanese Yen. Currency forward contracts are commitments to purchase or sell an agreed amount of foreign currency at a specified exchange rate at a specified future date. There were no option contracts outstanding at December 31,2000. Currency options, which are normally directly negotiated, allow but do not require, the holder to buy from or sell to the writer an agreed amount of currency at a specified exchange rate within a stated period, and involve the initial payment or receipt of a premium. The Group's option contracts have an average term of less than one year. There were no option contracts outstanding at December 31, 2000. Included in currency options are currency cylinder option contracts. A cylinder is the purchase of an option to buy foreign currency and the simultaneous selling of an option to sell the same amount of foreign currency to BP at a different exchange rate. The effect is to limit the risk of both gain and loss. This is achieved at little or no cost as the symmetry of the options means that the premium paid for one option is balanced by the premium received from the sale of the other. Oil and natural gas price risk management The Group enters into various types of oil and natural gas price contracts to manage its exposure to some movements in hydrocarbon prices as indicated in the following table. Contracts which are capable of being settled by delivery of oil, oil products or natural gas are excluded. <TABLE> <CAPTION> December 31, 2000 December 31, 1999 ------------------------------- ------------------------------ Gross Fair Fair Gross Fair Fair contract value value contract value value amount asset liability amount asset liability --------- --------- --------- --------- --------- --------- ($ million) <S> <C> <C> <C> <C> <C> <C> Oil Swaps................. 239 13 (13) 361 8 (13) Options............... 6 1 (1) -- -- -- Futures............... 189 5 (1) 143 5 -- --------- --------- --------- --------- --------- --------- 434 19 (15) 504 13 (13) ========= ========= ========= ========= ========= ========= Natural gas Swaps................. 2,511 133 (114) 4,346 55 (52) Options............... 7 10 (2) 7 -- -- Futures............... 96 4 -- 42 1 (2) --------- --------- --------- --------- --------- --------- 2,614 147 (116) 4,395 56 (54) ========= ========= ========= ========= ========= ========= </TABLE> F - 48
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (continued) The Group uses swaps, options and futures to hedge future purchases and sales of crude oil and refined oil products. The term of the oil price derivatives is usually less than one year. Natural gas swaps, options and futures are used to convert specific sales and purchase contracts from fixed prices to market prices. Swaps are also used to hedge exposure for price differentials between locations. The term of most natural gas price derivatives is less than one year, with some having terms of two years. Under swaps, BP agrees with other parties to pay or receive the difference between a fixed and variable price at a range of specified dates determined by reference to an agreed notional volume. The option and futures contracts are traded on regulated exchanges. Exchange-traded options allow, but do not require, the holder to either buy from or sell to the writer an agreed amount of futures contracts at a specified price at a specified future date. Futures are fixed price commitments to purchase or sell a contract, whose value is derived from the price of oil at a specified future date. Initial margin requirements and daily cash settlements for both these types of contracts are met either by bank guarantees or in cash. There is little credit risk under these contracts as regulated exchanges are the counterparties. Trading activities The Group maintains active trading positions in a variety of derivatives. This activity is undertaken in conjunction with risk management. Derivatives held for trading purposes are marked to market and any gain or loss recognized in the income statement. For traded derivatives, many positions have been neutralized, with trading initiatives being concluded by taking opposite positions to fix a gain or loss, thereby achieving a zero net market risk. The following table discloses the contract or notional amount and fair value of the derivatives held for trading purposes at December 31, 2000 and 1999 and the average fair value for the year. <TABLE> <CAPTION> Year ended December 31, 2000 Year ended December 31, 1999 ------------------------------- --------------------------------- Net Average Net Average Gross fair value fair value Gross fair value fair value contract asset asset contract asset asset amount (liability) (liability) amount (liability) (liability) --------- --------- --------- -------- ----------- ----------- ($ million) <S> <C> <C> <C> <C> <C> <C> Interest rate contracts Futures..................... -- -- -- 200 -- -- Options..................... -- -- -- -- -- -- Swaptions................... -- -- -- -- -- -- --------- --------- --------- --------- --------- --------- -- -- -- 200 -- -- ========= ========= ========= ========= ========= ========= Foreign exchange contracts Forwards.................... 2,388 (1) (3) 1,549 -- -- Options..................... 46 1 -- 125 -- -- --------- --------- --------- --------- --------- --------- 2,434 -- (3) 1,674 -- -- ========= ========= ========= ========= ========= ========= Oil price contracts Swaps....................... 3,549 35 1 2,372 (63) 62 Futures..................... 1,985 -- -- 470 -- -- Options..................... 782 1 3 302 4 6 --------- --------- --------- --------- --------- --------- 6,316 36 4 3,144 (59) 68 ========= ========= ========= ========= ========= ========= Natural gas price contracts Swaps....................... 36,129 40 19 -- -- -- Futures..................... -- (12) (4) -- -- -- Options..................... 77 (4) -- -- -- -- --------- --------- --------- --------- --------- --------- 36,206 24 15 -- -- -- ========= ========= ========= ========= ========= ========= </TABLE> F - 49
NOTES TO FINANCIAL STATEMENTS (Continued) Note 28 -- Derivative financial instruments (concluded) Concentrations of credit risk The primary activities of the Group are oil and gas exploration and production, gas and power marketing and trading, oil refining and marketing and the manufacture and marketing of chemicals. The Group's principal customers, suppliers and financial institutions with which it conducts business are located throughout the world. The credit ratings of interest rate and currency swap counterparties are all of at least investment grade. The credit quality is actively managed over the life of the swap. Note 29 -- Capital and reserves <TABLE> <CAPTION> Paid Share in Merger Other Retained capital surplus reserve reserve earnings Total -------- -------- -------- -------- --------- ----- ($ million) <S> <C> <C> <C> <C> <C> <C> At January 1, 2000.................. 4,892 3,684 697 -- 34,008 43,281 Exchange adjustment................. -- -- -- -- (2,508) (2,508) Employee share schemes.............. 17 250 -- -- -- 267 ARCO acquisition.................... 799 -- 26,172 456 -- 27,427 Share buyback....................... (55) 55 -- -- (2,001) (2,001) Stamp duty reserve tax.............. -- (295) -- -- -- (295) Qualifying Employee Share Ownership Trust (QUEST)........... -- 76 -- -- (76) -- Profit for the year................. -- -- -- -- 11,870 11,870 Dividends........................... -- -- -- -- (4,625) (4,625) ------ ------ ------ ------ ------ ------ At December 31, 2000................ 5,653 3,770 26,869 456 36,668 73,416 ====== ====== ====== ====== ====== ====== </TABLE> The movements in the Group's share capital during the year are set out above. All movements are quantified in terms of the number of BP shares issued or repurchased. ARCO acquisition. 3,228,273,878 ordinary shares were issued in connection with the ARCO acquisition, including 42,267,402 ordinary shares in respect of ARCO preference shares surrendered and ARCO employee share options exercised. Share buyback. The Company purchased for cancellation 221,662,972 ordinary shares for a total consideration of $2,001 million. Employee share schemes. During the year 38,111,531 ordinary shares were issued under employee share schemes. Certain of these shares were issued via a QUEST. See Note 33 for further details. F - 50
NOTES TO FINANCIAL STATEMENTS (Continued) Note 30 -- Retained earnings Retained earnings of $36,668 million ($34,008 million at December 31, 1999) include the following amounts, the distribution of which is limited by statutory or other restrictions: <TABLE> <CAPTION> December 31, --------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Parent company....................................................... 17,547 16 Subsidiary undertakings.............................................. 9,120 5,638 Associated undertakings.............................................. 1,042 1,649 ------ ------ 27,709 7,303 ====== ====== </TABLE> Cumulative net exchange losses of $3,882 million are included in retained earnings ($1,374 million losses at December 31, 1999). There were no unrealized currency translation differences for the year on long-term borrowings used to finance equity investments in foreign currencies (1999 nil and 1998 nil). Note 31 -- Analysis of consolidated statement of cash flows (i) Reconciliation of historical cost profit before interest and tax to net cash inflow from operating activities <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Historical cost profit before interest and tax........... 18,704 8,342 5,980 Depreciation and amounts provided........................ 7,449 4,965 5,301 Exploration expenditure written off...................... 264 304 373 Share of profits of joint ventures and associated undertakings (1,853) (1,704) (1,102) Interest and other income................................ (360) (217) (272) (Profit) loss on sale of businesses and fixed assets..... (196) 379 (963) Charge for provisions.................................... 702 847 377 Utilization of provisions................................ (969) (597) (460) (Increase) decrease in inventories....................... (1,449) (1,562) 584 (Increase) decrease in debtors........................... (5,587) (4,013) 1,768 Increase (decrease)in payables........................... 3,711 3,546 (2,000) ------ ------ ------ Net cash inflow from operating activities................ 20,416 10,290 9,586 ====== ====== ====== </TABLE> (ii) Exceptional items The cash outflow in respect of the restructuring costs charged in 1999 was $446 million (1999 $976 million). The cash outflow in 1999 relating to the merger expenses charged in 1998 was $166 million (1998 $32 million). Both amounts were included in the net cash inflow from operating activities. F - 51
NOTES TO FINANCIAL STATEMENTS (Continued) Note 31-- Analysis of consolidated statement of cash flows (concluded) (iii) Financing <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Long-term borrowing.................................. (1,680) (2,140) (2,078) Repayments of long-term borrowing.................... 2,353 2,268 1,208 Short-term borrowing................................. (4,120) (3,136) (631) Repayments of short-term borrowing................... 4,821 2,299 701 ----- ------ ------ 1,374 (709) (800) Issue of ordinary share capital...................... (257) (245) (161) Share buyback........................................ 2,001 -- 584 Stamp duty reserve tax............................... 295 -- -- ----- ------ ------ Net cash outflow (inflow) ........................... 3,413 (954) (377) ===== ====== ====== </TABLE> (iv) Management of liquid resources Liquid resources comprise current asset investments which are principally commercial paper issued by other companies. The net cash outflow from the management of liquid resources was $452 million (1999 $93 million inflow and 1998 $596 million inflow). (v) Commercial paper Net movements in commercial paper are included within short-term borrowings or repayment of short-term borrowings as appropriate. (vi) Movement in net debt <TABLE> <CAPTION> Years ended December 31, ------------------------------------------------------------------------------------------ 2000 1999 -------------------------------------------- -------------------------------------------- Current Current Finance asset Net Finance asset Net debt Cash investments debt debt Cash investments debt ------- ------- ----------- ------- ------- ------- ----------- ------- ($ million) <S> <C> <C> <C> <C> <C> <C> <C> <C> At January 1.......... (14,544) 1,331 220 (12,993) (13,755) 405 470 (12,880) Exchange adjustments.. 96 (39) (11) 46 (13) (39) (7) (59) Net cash flow......... 1,374 (122) 452 1,704 (709) 965 (93) 163 Acquisitions.......... (8,072) -- -- (8,072) -- -- -- -- Other movements....... (44) -- -- (44) (67) -- (150) (217) ------ ------ ------ ------ ------ ------ ------ ------ At December 31........ (21,190) 1,170 661 (19,359) (14,544) 1,331 220 (12,993) ====== ====== ====== ====== ====== ====== ====== ====== </TABLE> F - 52
NOTES TO FINANCIAL STATEMENTS (Continued) Note 32 -- Operating lease commitments Annual commitments under operating leases were as follows: <TABLE> <CAPTION> December 31, ----------------------------------------------- 2000 1999 ----------------------------------------------- Land and Land and buildings Other buildings Other --------- --------- --------- --------- ($ million) <S> <C> <C> <C> <C> <C> Expiring within: 1 year.................. 41 181 19 107 2 to 5 years............ 54 330 57 372 Thereafter.............. 235 220 163 250 --------- --------- --------- --------- 330 731 239 729 ========= ========= ========= ========= </TABLE> The minimum future lease payments (after deducting related rental income from operating sub-leases of $345 million) were as follows: <TABLE> <CAPTION> December 31, 2000 ------------ ($million) <S> <C> 2001 ............................................................... 1,016 2002 ............................................................... 839 2003 ............................................................... 680 2004 ............................................................... 561 2005 ............................................................... 469 Thereafter........................................................... 2,324 ------- 5,889 ======= </TABLE> F - 53
NOTES TO FINANCIAL STATEMENTS (Continued) Note 33 -- Employee share schemes BP offers most of its employees the opportunity to acquire a shareholding in the Company through savings related and matching arrangements; the latter may be participating share schemes or savings plans. BP also uses a long-term performance plan (see Note 34) and the granting of share options as elements of employee remuneration. Under the BP Savings Related Share Option Scheme employees save monthly over a three-or five-year period towards the purchase of shares at a price fixed when the option is granted. The option price is usually set at a 20% discount to the market price at the time of grant. The option must be exercised within six months of maturity of the savings contract otherwise it lapses. The scheme is run in the UK and in a number of other countries. Under the BP Participating Scheme, BP matches employees' own contribution of shares, up to a predetermined limit, all of which are then held in trust for defined periods before being released to the employee. The scheme is run in the UKand in a number of other countries. A further 20 countries implemented a participating share plan during 2000. The Company sponsors a number of savings plans covering most US employees. Under these plans, employees may contribute up to 18% of their salary subject to certain regulatory limits. The employee receives a dollar-for-dollar Company matched contribution for the first 7% of eligible pay contributed to most of these plans on a before-tax or after-tax basis or a combination of both. Company contributions are initially invested in BPADS funds, but employees may transfer those amounts and may invest their own contributions in more than 200 investment options. The Company's contributions vest over a period of five years. Company contributions to savings plans during the year were $101 million (1999 $95 million and 1998 $91 million). During 2000, BP granted options under the BP Share Option Plan to certain categories of employees. Options were granted to heritage-Amoco employees who, under the terms of the merger agreement between BP and Amoco, must, for 1999 and 2000, be granted options on a similar basis to the arrangements under the Amoco 1991 Incentive Program. Options were also granted to certain heritage-BP US employees. The options were granted at the market price at the date of grant. There are no performance conditions attaching to these grants. The options are exercisable one or two years after the date of grant, and lapse after 10 years. Also in 2000, options were granted to non-US middle managers. The options were granted at market price at the date of grant and are not exercisable until a performance condition is satisfied. Before any options can be exercised, the total return to shareholders (share price increase with all dividends reinvested) on an investment in BP shares is required to exceed the mean total return to shareholders of a representative Group of UK companies by a margin set from time to time. The performance period for each grant will normally be three years. Subject to achievement of the performance conditions, the options are exercisable between the third and tenth anniversaries of the date of grant. In accordance with their normal timetable, options were granted to ARCO employees in February 2000. All options granted prior to April 1, 1999, the date of the acquisition announcement, became exercisable immediately on completion of the acquisition in April 2000 at the discretion of the employee. Burmah Castrol employees eligible to receive options in 2000 were granted options under the BP Share Option Plan, with certain rule modifications, after completion of the acquisition. For options granted prior to the acquisition, employees were generally offered the choice of cashing out their existing options or converting them to BP share options. An Employee Share Ownership Plan (ESOP) was established in 1997 to acquire BP shares to satisfy future requirements of certain employee share schemes. The Company provides funding to the ESOP. The assets and liabilities of the ESOP are recognized as assets and liabilities of the Company within these accounts. The ESOP has waived its rights to dividends. During 2000 the ESOP released 9,412,931 shares for the participating share schemes. The cost of shares released for these schemes has been charged in these accounts. At December 31, 2000 the ESOP held 45,515,000 shares (December 31, 1999, 53,989,000 shares). F - 54
NOTES TO FINANCIAL STATEMENTS (Continued) Note 33 -- Employee share schemes (continued) BP has established a Qualifying Employee Share Ownership Trust (QUEST) for the purposes of share option schemes for employees. During the year, contributions of $76 million (1999 $61 million and 1998 $42 million) were made by the Company to the QUEST which, together with option-holder contributions, were used by the QUEST to subscribe for new ordinary shares at market price. The Company has transferred the cost of this contribution directly to retained profits and the excess of the subscription price over nominal value has increased the share premium account. At December 31, 2000, all the 12,245,011 ordinary shares issued to the QUEST had been transferred to option holders exercising options under the BP Group Savings Related Share Option and Burmah Castrol Sharesave Schemes. <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ (options thousands) <S> <C> <C> <C> Employee share options granted during the year: Savings related schemes............................ 7,930 8,828 9,734 BP Share Option Plan............................... 50,461 41,054 -- BP Executive Share Option Scheme................... -- -- 2,576 Amoco Stock Option Plan............................ -- -- 60,696 ------ ------ ------ 58,391 49,882 73,006 ====== ====== ====== </TABLE> The exercise prices for BP options granted during the year were (pound)4.98/$7.42 (7,930,099 options) for savings-related and similar schemes and (pound)5.44/$8.22 (weighted average price) for 50,460,784 options granted under the share option plan. <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ (shares thousands) <S> <C> <C> <C> Shares issued in respect of options exercised during the year: Savings related schemes............................. 13,709 12,176 12,582 BP, Amoco and Burmah Castrol executive share option plans 23,280 51,472 40,894 ------ ------ ------ 36,989 63,648 53,476 ====== ====== ====== </TABLE> In addition 1,123,000 shares (1999, 2,514,000 shares and 1998, 3,298,000 shares) were issued, and 9,413,000 shares (1999, 8,779,000 shares and 1998, 8,518,000 shares) released from the ESOP for participating share schemes. <TABLE> <CAPTION> 2000 1999 1998 ------ ------ ------ <S> <C> <C> <C> Options outstanding at December 31: (shares thousands) BP options ......................................... 342,509 323,161 346,898 Exercise period..................................... 2001-2010 2000-2009 1999-2008 Price............................................... $1.92-$9.97 $2.09-$10.10 $1.85-$7.88 </TABLE> F - 55
NOTES TO FINANCIAL STATEMENTS (Continued) Note 33 -- Employee share schemes (continued) Share option transactions under employee share schemes are summarized as follows: <TABLE> <CAPTION> Years ended December 31, ---------------------------------------------------------------------- 2000 1999 1998 -------------------- --------------------- ------------------- Weighted Weighted Weighted average average average Number of exercise Number of exercise Number of exercise shares price shares price shares price --------- -------- --------- -------- --------- -------- ($) ($) ($) <S> <C> <C> <C> <C> <C> <C> Outstanding at January 1...... 323,161,387 4.95 346,897,822 4.34 336,066,100 3.85 Burmah Castrol................ 3,293,317 5.02 -- -- -- -- Reinstated.................... 3,729 2.94 37,480 5.24 33,486 2.82 Granted....................... 58,390,883 8.17 49,882,128 7.88 73,005,560 5.64 Exercised..................... (37,029,467) 3.76 (63,711,433) 3.85 (53,475,492) 3.00 Stock appreciation rights exercised................... -- -- (542,772) 3.30 (698,720) 2.56 Cancelled..................... (5,310,803) 6.72 (9,401,838) 5.54 (8,033,112) 4.73 ------------ ------------ ----------- Outstanding at December 31.... 342,509,046 5.61 323,161,387 4.95 346,897,822 4.34 ============ ============ =========== Exercisable at December 31.... 229,987,199 206,116,577 202,132,716 ============ ============ =========== Available for grant at December 31................1,234,983,212 1,087,626,398 1,177,618,184 ============= ============= ============= </TABLE> Options outstanding at December 31, 2000 will be exercisable between 2001 and 2010. For the share options outstanding and exercisable at December 31, 2000 the exercise price ranges and average remaining lives were: <TABLE> <CAPTION> Options outstanding Options exercisable ------------------------------ -------------------- Weighted Weighted Weighted average average average Number of remaining exercise Number of exercise Shares life price shares price ---------- --------- -------- --------- -------- (years) ($) ($) <S> <C> <C> <C> <C> <C> Range of exercise prices $1.92 - $3.62................. 76,049,100 2.12 3.32 70,909,845 3.30 $3.72 - $4.80................. 65,422,386 4.40 4.37 54,974,111 4.31 $4.81 - $7.28................. 106,387,934 6.19 5.78 87,234,521 5.57 $7.52 - $9.97................. 94,649,626 8.46 8.11 16,868,722 7.99 ----------- ---- ---- ---------- ---- 342,509,046 5.57 5.61 229,987,199 4.75 =========== ==== ==== =========== ==== </TABLE> F - 56
NOTES TO FINANCIAL STATEMENTS (Continued) Note 33 -- Employee share schemes (concluded) As allowed by SFAS 123 `Accounting for Stock-Based Compensation' the Company has elected to continue to follow Accounting Principles Board Opinion No. 25, 'Accounting for Stock Issued to Employees'. In accordance with this accounting statement the Company does not recognize compensation expense on the grant of the options. Had compensation expense been determined based upon the fair value of the stock options at grant date consistent with the method of SFAS 123, the Company's profit for the year and profit per ordinary share for 2000 would have been reduced by $122 million (1999 $65 million and 1998 $47 million) and 1 cent (1999 1 cent and 1998 1 cent), respectively. The weighted average fair value of BP share options granted in 2000 was $2.33 (1999 $2.27 and 1998 $2.29). The fair value of each option grant was estimated on the date of grant using a Black-Scholes option pricing model with the following assumptions for 2000, 1999 and 1998, respectively; risk-free interest rates of 6.0, 6.5 and 6.0%; dividend yield of 3%; expected lives of one, two, three or five years as appropriate and volatility of 33%, 32% and 18%. In 1998 and earlier years Amoco had granted stock options. Following the merger between BP and Amoco these were converted into BP share options. The weighted average fair value of Amoco stock options granted in 1998 was $7.40. On the basis of BP shares this equates to a value of $1.86. The fair value of each option grant was estimated on the date of grant using a Black-Scholes option pricing model with the following assumptions for 1998; risk-free interest rates of 5.7 dividend yield of 4%, expected lives of six years and volatility of 17%. The effects of applying SFAS 123 for the proforma disclosures are not representative of the effects expected on reported net income and profit per ordinary share in future years, since the disclosures do not reflect compensation expense for options granted prior to 1995. Note 34 -- Long Term Performance Plan During 2000 the executive directors and senior executives participated in the Long Term Performance Plan (the Plan). This is an incentive scheme under which the Company may award shares to participants or fund the purchase of shares for participants if long-term targets are met. The cost of potential future awards is accrued over the three-year performance periods of each Plan. In any one year, three Plans are in operation. The amount charged in 2000 was $119 million (1999 $128 million and 1998 $45 million). The value of awards under the 1997-99 Plan made in 2000 was $78 million (1996-98 Plan $52 million). Employee Share Ownership Plans (ESOPs) have been established to acquire BP shares to satisfy any awards made to participants under the Plan and then to hold them for the participants during the retention period of the Plan. In order to hedge the cost of potential future awards the ESOPs may, from time to time over the performance period of the Plans, purchase BP shares in the open market. The Company provides funding to the ESOPs. The assets and liabilities of the ESOPs are recognized as assets and liabilities of the Company within these accounts. The ESOPs have waived their rights to dividends. At December 31, 2000 the ESOPs held 9,507,000 (1999, 9,502,000) shares for potential future awards. F - 57
NOTES TO FINANCIAL STATEMENTS (Continued) Note 35 -- Directors' remuneration <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ thousand) <S> <C> <C> <C> Total for all directors Emoluments (a)................................................. 14,432 13,309 6,870 Compensation for loss of office................................ 680 6,126 -- Gains made on the exercise of share options.................... 2,812 5,158 888 Amounts awarded under long-term incentive schemes.............. 15,152 7,594 4,434 ====== ====== ====== Highest paid director Emoluments..................................................... 2,762 2,434 1,514 Gains made on the exercise of share options.................... -- 4,509 806 Amount awarded under long-term incentive schemes............... 3,649 -- 1,331 Accrued pension at December 31................................. 820 1,172 626 ====== ====== ====== </TABLE> - ---------- (a) Fees in 1998 of $45,730 in respect of Mr H M P Miles' services as a non-executive director were paid to his employer. Emoluments These amounts comprise fees paid to the non-executive chairman and non-executive directors, and, for executive directors, salary and benefits earned during the relevant financial year, plus bonuses awarded for the year. Pension contributions Six executive directors participate in a non-contributory pension scheme established for UK staff by a separate trust fund to which contributions are made by BP based on actuarial advice. There were no contributions to this pension scheme in 2000, 1999 and 1998. Three US executive directors participated in the BP Retirement Accumulation Plan. Note 36 -- Loans to officers Miss J C Hanratty has a low interest loan of $43,000 made to her prior to her appointment as Company Secretary on October 1, 1994. F - 58
NOTES TO FINANCIAL STATEMENTS (Continued) Note 37 -- Employee costs and numbers <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Employee costs Wages and salaries................................... 6,764 5,302 4,995 Social security costs................................ 455 359 412 Pension costs........................................ 125 (97) 139 ------ ------ ------ 7,344 5,564 5,546 ====== ====== ====== </TABLE> <TABLE> <CAPTION> At December 31, ------------------------ 2000 1999 1998 ------ ------ ------ <S> <C> <C> <C> Number of employees Exploration and Production........................... 16,000 12,500 18,000 Gas and Power........................................ 1,000 800 800 Refining and Marketing (a)........................... 67,700 45,250 52,100 Chemicals............................................ 17,600 18,700 23,050 Other businesses and corporate....................... 4,900 3,150 2,700 ------ ------ ------- 107,200 80,400 96,650 ====== ====== ======= </TABLE> <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- <S> <C> <C> <C> <C> <C> Average number of employees Year ended December 31, 2000 Exploration and Production............. 3,250 650 4,700 5,700 14,300 Gas and Power.......................... 550 50 200 100 900 Refining and Marketing ................ 9,600 13,700 26,200 10,900 60,400 Chemicals.............................. 3,700 4,600 8,100 1,400 17,800 Other businesses and corporate......... 1,100 400 2,400 700 4,600 -------- -------- -------- -------- -------- 18,200 19,400 41,600 18,800 98,000 ======== ======== ======== ======== ======== Year ended December 31, 1999 Exploration and Production............. 3,500 850 5,100 5,500 14,950 Gas and Power.......................... 450 50 200 100 800 Refining and Marketing (b)............. 9,600 10,050 20,700 8,150 48,500 Chemicals.............................. 4,100 4,900 9,850 2,000 20,850 Other businesses and corporate......... 1,150 350 1,000 500 3,000 -------- -------- -------- -------- -------- 18,800 16,200 36,850 16,250 88,100 ======== ======== ======== ======== ======== Year ended December 31, 1998 Exploration and Production 3,600 850 7,750 6,150 18,350 Gas and Power 450 50 150 50 700 Refining and Marketing (c)............. 10,300 9,700 23,600 9,150 52,750 Chemicals.............................. 4,650 5,150 11,600 2,450 23,850 Other businesses and corporate......... 950 300 1,550 450 3,250 -------- -------- -------- -------- -------- 19,950 16,050 44,650 18,250 98,900 ======== ======== ======== ======== ======== </TABLE> - --------------- (a) 1999 includes 18,050 (1998, 17,300) employees assigned to the BP/Mobil joint venture. (b) Includes 7,800 employees assigned to the BP/Mobil joint venture in the UK and 9,650 employees in the Rest of Europe. (c) Includes 8,550 employees assigned to the BP/Mobil joint venture in the UK and 9,350 employees in the Rest of Europe. F - 59
NOTES TO FINANCIAL STATEMENTS (Continued) Note 38 -- Pensions Most Group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided by defined contribution plans, whereby retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee; or by defined benefit plans, whereby retirement benefits are based on employee final pensionable salary and length of service. Defined benefit plans may be externally funded or unfunded. The assets of funded plans are generally held in separately administered trusts. Contributions to funded defined benefit plans are based on advice from independent actuaries using actuarial methods, the objective of which is to provide adequate funds to meet pension obligations as they fall due. No contributions were made to the UK pension fund during 2000, 1999 and 1998. For unfunded plans, where assets are not held with the specific purpose of matching pension obligations the accrued liability for pension benefits is included within other provisions. The majority of the Group's employees are members of defined benefit schemes. The principal plans are reviewed annually by the independent actuaries and subject to a formal actuarial valuation every three years. Pension costs for the principal plans have been derived using the projected unit credit method and by amortizing surpluses and deficits on a straight line basis over the average expected remaining service lives of the current employees. The main assumptions used in calculating the credit/charge for the principal plans were as follows: <TABLE> <CAPTION> Years ended December 31, ---------------------------------------------- 2000 1999 1998 ---------- ---------- ---------- <S> <C> <C> <C> UK and other European plans: Rate of return on assets............ 6.5% 6.1% 7% Discount rate....................... 6.5% 6.1% 7% Future salary increases............. 4.8% 4.3% 5.1% Future pension increases............ 2.9% 2.5% 3.2% Dividend growth..................... n/a n/a n/a US plans: Rate of return on assets............ 10% 10% 10% Discount rate....................... 7.5% 6.5% 6.9% Future salary increases............. 4% 4% 4.7% Future pension increases............ nil nil nil Dividend growth..................... n/a n/a n/a </TABLE> - ---------- n/a = not applicable F - 60
NOTES TO FINANCIAL STATEMENTS (Continued) Note 38 -- Pensions (continued) <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Principal plans: Service cost-- benefits earned during year......... 364 347 375 Interest cost on projected benefit obligation...... 1,211 999 1,089 Expected return on plan assets..................... (1,625) (1,273) (1,339) Amortization of transition asset................... (72) (83) (84) Recognized net actuarial gain...................... (203) (108) (87) Recognized prior service cost...................... 78 17 14 Curtailment and settlement (gains) losses.......... (119) (150) 12 Special termination benefits....................... 233 3 -- ------ ------ ------ (133) (248) (20) Other defined benefit plans.......................... 38 30 51 Defined contribution schemes......................... 220 121 108 ------ ------ ------ Total pension (income) expense....................... 125 (97) 139 ====== ====== ====== </TABLE> At January 1, 2000, the date of the latest actuarial valuations or reviews, the market value and actuarial value of assets in the Group's major externally funded pension plans in the UK and the USA was $25,520 million ($23,209 million at January 1, 1999) and $20,474 million ($19,185 million at January 1, 1999) respectively. The actuarial value of the assets of these plans represented 130% (125% at January 1, 1999) of the benefits that had accrued to members of those plans, after allowing for expected future increases in salaries. At December 31, 2000 the obligation for accrued benefits in respect of the major unfunded schemes in Europe was $1,438 million ($1,513 million at December 31, 1999). Of this amount, $1,167 million ($1,234 million at December 31, 1999) has been provided in these accounts. Further information in respect of the Group's principal defined benefit pension plans required under FASB Statement of Financial Accounting Standards No. 132 -- 'Employers' Disclosures about Pensions and Other Postretirement Benefits' is set out below. F - 61
NOTES TO FINANCIAL STATEMENTS (Continued) Note 38 -- Pensions (continued) <TABLE> <CAPTION> UK and Other European plans US plans ---------------- ---------------- 2000 1999 2000 1999 ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Benefit obligation at January 1.................. 12,590 12,670 3,827 4,424 Service cost..................................... 235 229 129 118 Interest cost.................................... 832 723 380 276 Plan amendments.................................. 809 47 -- 71 Curtailments, settlements and special termination benefits........................... -- -- 191 (15) Actuarial (gain) loss............................ 670 130 40 (93) Acquisitions..................................... 1,241 -- 2,308 -- Plan participants' contributions................. 24 21 -- -- Settlement payments.............................. -- -- (423) (668) Benefit payments................................. (657) (639) (906) (286) Exchange adjustment.............................. (1,093) (591) -- -- ------ ------ ------ ------ Benefit obligation at December 31................ 14,651 12,590 5,546 3,827 ------ ------ ------ ------ Fair value of plan assets at January 1........... 20,189 17,991 5,331 5,230 Actual return on plan assets..................... 216 3,280 (118) 981 Acquisitions..................................... 1,344 -- 2,817 -- Plan participants' contributions................. 24 21 -- -- Employer contributions........................... 14 -- 290 74 Settlement payments.............................. -- -- (444) (668) Benefit payments................................. (563) (534) (906) (286) Exchange adjustment.............................. (1,607) (569) -- -- ------ ------ ------ ------ Fair value of plan assets at December 31......... 19,617 20,189 6,970 5,331 ------ ------ ------ ------ Funded status.................................... 4,966 7,599 1,424 1,504 Unrecognized transition asset.................... (168) (252) (5) (14) Unrecognized net actuarial (gain) loss........... (4,821) (7,012) 133 (740) Unrecognized prior service cost.................. 792 135 11 13 ------ ------ ------ ------ Net amount recognized............................ 769 470 1,563 763 ====== ====== ====== ====== Prepaid benefit cost............................. 1,937 1,704 1,672 837 Accrued benefit liability........................ (1,392) (1,473) (159) (142) Intangible asset................................. 50 78 3 5 Accumulated other comprehensive income........... 174 161 47 63 ------ ------ ------ ------ 769 470 1,563 763 ====== ====== ====== ====== </TABLE> F - 62
NOTES TO FINANCIAL STATEMENTS (Continued) Note 38 -- Pensions (concluded) Major assumptions used to determine projected benefit obligations for the principal pension plans were as follows: <TABLE> <CAPTION> December 31, ---------------------------------- 2000 1999 1998 ---------- ---------- ---------- <S> <C> <C> <C> UK and other European plans: Compensation increase........................... 4.8% 4.8% 4.3% Discount rate................................... 6.5% 6.5% 6.1% US plans: Compensation increase........................... 4.0% 4.0% 4.7% Discount rate................................... 7.5% 7.5% 6.5% </TABLE> Plan assets are held in equity securities, fixed income securities and real estate. Note 39 -- Other postretirement benefits Certain Group companies in the USA provide postretirement healthcare and life insurance benefits to their retired employees and dependants. The entitlement to these benefits is usually based on the employee remaining in service until retirement age and completion of a minimum period of service. The plans are funded to a limited extent and the accrued net liability for postretirement benefits is included within other provisions. The cost of providing postretirement benefits is assessed annually by independent actuaries using the projected unit credit method. The assumptions used in calculating the charge for postretirement benefits are consistent with those shown in Note 38 for US pension plans. The charge to income for postretirement benefits is as follows: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Service cost-- benefits earned during year........... 25 34 39 Interest cost on projected benefit obligation........ 148 113 114 Expected return on plan assets....................... (5) (4) (1) Recognized net actuarial gain........................ (46) (31) (28) Amortization of prior service cost recognized........ (20) (8) (23) Curtailment gains.................................... (40) (62) -- ------ ------ ------ Postretirement benefit expense....................... 62 42 101 ====== ====== ====== </TABLE> At December 31, 2000 the independent actuaries has reassessed the obligation for postretirement benefits at $2,562 million ($1,638 million at December 31, 1999). The provision for postretirement benefits at 31 December 2000 was $2,726 million ($2,244 million at December 31, 1999). The discount rate used to assess the obligation at December 31, 2000 was 7.5% (7.5% at December 31, 1999). The assumed future healthcare cost trend rate for 2001 is 15%, for 2002 is 10% and for 2003 and subsequent years is 5%. F - 63
NOTES TO FINANCIAL STATEMENTS (Continued) Note 39 -- Other postretirement benefits (concluded) Further information presented in compliance with the requirements of FASB Statement of Financial Accounting Standards No. 132 -- 'Employers' Disclosures about Pensions and Other Postretirement Benefits' is set out below. <TABLE> <CAPTION> 2000 1999 ------ ------ ($ million) <S> <C> <C> Benefit obligation at January 1........................... 1,638 1,814 Service cost.............................................. 25 34 Interest cost............................................. 148 113 Plan amendments........................................... -- 22 Curtailment gain.......................................... (9) (21) Actuarial (gain) loss..................................... 340 (214) Acquisitions.............................................. 579 -- Benefit payments.......................................... (159) (110) ------ ------ Benefit obligation at December 31......................... 2,562 1,638 ------ ------ Fair value of plan assets at January 1.................... 53 49 Actual return on plan assets.............................. -- 6 Employer contributions.................................... (4) (2) ------ ------ Fair value of plan assets at December 31.................. 49 53 ------ ------ Funded status............................................. (2,513) (1,585) Unrecognized net actuarial gain........................... (144) (570) Unrecognized prior service cost........................... (69) (89) ------ ------ Provision for postretirement benefits..................... (2,726) (2,244) ====== ====== </TABLE> The assumed healthcare cost trend rate has a significant effect on the amounts reported. A one-percentage-point change in the assumed healthcare cost trend rate would have the following effects: <TABLE> <CAPTION> 1-Percentage 1-Percentage point increase point decrease -------------- -------------- ($ million) <S> <C> <C> Effect on total of service and interest cost in 2000........ 26 (21) Effect on postretirement obligation at December 31, 2000.... 265 (219) </TABLE> F - 64
NOTES TO FINANCIAL STATEMENTS (Continued) Note 40 -- Contingent Liabilities There were contingent liabilities at December 31, 2000 in respect of guarantees and indemnities entered into as part of the ordinary course of the Group's business. No material losses are likely to arise from such contingent liabilities. Approximately 200 lawsuits were filed in State and Federal Courts in Alaska seeking compensatory and punitive damages arising out of the Exxon Valdez oil spill in Prince William Sound in March 1989. Most of those suits named Exxon (now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies which own Alyeska. Alyeska initially responded to the spill until the response was taken over by Exxon. BP owns a 50% interest in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BP's combination with ARCO. In April 2000 that 20% interest was sold to Phillips Petroleum Company (Phillips), subject to BP's agreement to indemnify Phillips if certain liabilities exceeded a defined amount. Alyeska and its owners have settled all of the claims against them under these lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages which it has incurred. If any claims are asserted by Exxon which affect Alyeska and its owners, BP would defend the claims vigorously. The Group 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 Group to take future action to remediate the effects on the environment of prior disposal or release of chemical or petroleum substances by the Group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, service stations, terminals and waste disposal sites. In addition, the Group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its cost is inherently difficult to estimate. However, the estimated cost of known environmental obligations has been provided in these accounts in accordance with the Group's accounting policies. While the amounts of future costs could be significant and could be material to the Group's results of operations in the period in which they are recognized, BP does not expect these costs to have a material effect on the Group's financial position or liquidity. F - 65
NOTES TO FINANCIAL STATEMENTS (Continued) Note 41 -- Joint ventures and associated undertakings The significant joint ventures of the BP Group at December 31, 2000 are shown in Note 45. The pan-European refining and marketing joint venture with ExxonMobil was dissolved on August 1, 2000. Within the BP/Mobil joint venture, BP operated and had a 70% interest in the fuels refining and marketing operation and had a 49% interest in the lubricants business. On dissolution, BP acquired most of the ExxonMobil assets used by the fuels refining and marketing operation. During the year the BP Group sold crude oil and products totalling $2,933 million (1999 $3,398 million and 1998 $2,264 million) to the BP/Mobil joint venture and purchased crude oil and products totalling $1,762 million (1999 $1,791 million and 1998 $1,335 million). At December 31, 1999 the Group share of joint venture's fixed assets was $5,366 million, current assets $4,582 million, liabilities due within one year $4,172 million and liabilities due after one year $572 million. Significant associated undertakings of the BP Group at December 31, 2000 are shown in Note 45. During the year the BP Group purchased crude oil from two associated undertakings, Abu Dhabi Marine Areas and Abu Dhabi Petroleum to the value of $1,619 million (1999 $935 million and 1998 $715 million). At December 31, 2000 $137 million ($119 million at December 31, 1999) was payable in respect of these purchases. During the year the BP Group sold chemical feedstocks totalling $718 million (1999 $460 million and 1998 $395 million) to Erdoelchemie, an associated undertaking, and bought petrochemicals to the value of $114 million (1999 $77 million and 1998 $76 million). At December 31, 2000 the outstanding balance receivable from Erdoelchemie was $nil ($1 million at December 31, 1999). F - 66
NOTES TO FINANCIAL STATEMENTS (Continued) Note 42-- Oil and gas exploration and production activities (a) Capitalized costs at December 31 <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> 2000 Gross capitalized costs: Proved properties.................... 24,319 2,683 38,494 19,607 85,103 Unproved properties.................. 482 73 1,754 3,449 5,758 -------- -------- -------- -------- -------- 24,801 2,756 40,248 23,056 90,861 Accumulated depreciation (b)........... 13,182 1,797 18,204 8,933 42,116 -------- -------- -------- -------- -------- Net capitalized costs.................. 11,619 959 22,044 14,123 48,745 ======== ======== ======== ======== ======== 1999 Gross capitalized costs: Proved properties.................... 22,874 2,738 35,826 14,166 75,604 Unproved properties.................. 412 79 741 2,067 3,299 -------- -------- -------- -------- -------- 23,286 2,817 36,567 16,233 78,903 Accumulated depreciation (b)........... 13,160 1,890 20,751 8,279 44,080 -------- -------- -------- -------- -------- Net capitalized costs.................. 10,126 927 15,816 7,954 34,823 ======== ======== ======== ======== ======== 1998 Gross capitalized costs: Proved properties.................... 23,290 2,934 35,383 15,078 76,685 Unproved properties.................. 400 76 890 1,915 3,281 -------- -------- -------- -------- -------- 23,690 3,010 36,273 16,993 79,966 Accumulated depreciation (b)........... 12,670 1,865 20,741 8,183 43,459 -------- -------- -------- -------- -------- Net capitalized costs.................. 11,020 1,145 15,532 8,810 36,507 ======== ======== ======== ======== ======== </TABLE> F - 67
NOTES TO FINANCIAL STATEMENTS (Continued) Note 42-- Oil and gas exploration and production activities (a) (continued) Costs incurred for the year ended December 31 <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> 2000 Acquisition of properties: Proved............................... 2,954 -- 9,152 2,647 14,753 Unproved............................. 161 -- 508 1,880 2,549 -------- -------- -------- -------- -------- 3,115 -- 9,660 4,527 17,302 Exploration and appraisal costs (c).... 86 67 676 466 1,295 Development costs...................... 808 153 2,328 1,274 4,563 -------- -------- -------- -------- -------- Total costs............................ 4,009 220 12,664 6,267 23,160 ======== ======== ======== ======== ======== 1999 Acquisition of properties: Proved............................... -- -- 396 -- 396 Unproved............................. -- -- 23 130 153 -------- -------- -------- -------- -------- -- -- 419 130 549 Exploration and appraisal costs (c).... 83 39 287 439 848 Development costs...................... 676 71 1,212 956 2,915 -------- -------- -------- -------- -------- Total costs............................ 759 110 1,918 1,525 4,312 ======== ======== ======== ======== ======== 1998 Acquisition of properties: Proved............................... -- -- 3 54 57 Unproved............................. -- 1 58 62 121 -------- -------- -------- -------- -------- -- 1 61 116 178 Exploration and appraisal costs (c).... 177 106 476 764 1,523 Development costs...................... 1,432 100 1,670 1,569 4,771 -------- -------- -------- -------- -------- Total costs............................ 1,609 207 2,207 2,449 6,472 ======== ======== ======== ======== ======== </TABLE> F - 68
NOTES TO FINANCIAL STATEMENTS (Continued) Note 42-- Oil and gas exploration and production activities (a) (continued) Results of operations for the year ended December 31 <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> 2000 Turnover (d): Third parties........................ 3,538 926 4,242 2,446 11,152 Sales between businesses............. 3,191 138 6,755 5,593 15,677 -------- -------- -------- -------- -------- 6,729 1,064 10,997 8,039 26,829 -------- -------- -------- -------- -------- Exploration expense.................... 36 42 257 264 599 Production costs....................... 772 86 1,311 786 2,955 Production taxes....................... 641 6 437 911 1,995 Other costs (income) (e)............... 74 6 1,624 1,889 3,593 Depreciation and amounts provided...... 1,453 98 2,406 748 4,705 -------- -------- -------- -------- -------- 2,976 238 6,035 4,598 13,847 -------- -------- -------- -------- -------- Profit before taxation (f)............. 3,753 826 4,962 3,441 12,982 Allocable taxes........................ 1,127 516 1,042 1,018 3,703 -------- -------- -------- -------- -------- Results of operations ................. 2,626 310 3,920 2,423 9,279 ======== ======== ======== ======== ======== 1999 Turnover (d): Third parties........................ 2,258 644 4,738 2,216 9,856 Sales between businesses............. 2,251 108 1,283 2,938 6,580 -------- -------- -------- -------- -------- 4,509 752 6,021 5,154 16,436 -------- -------- -------- -------- -------- Exploration expense.................... 51 20 172 305 548 Production costs....................... 734 98 1,387 756 2,975 Production taxes....................... 167 2 283 495 947 Other costs (income) (e)............... 157 16 1,231 1,143 2,547 Depreciation and amounts provided...... 1,306 138 1,113 651 3,208 -------- -------- -------- -------- -------- 2,415 274 4,186 3,350 10,225 -------- -------- -------- -------- -------- Profit before taxation (f)............. 2,094 478 1,835 1,804 6,211 Allocable taxes........................ 643 312 483 497 1,935 -------- -------- -------- -------- -------- Results of operations ................. 1,451 166 1,352 1,307 4,276 ======== ======== ======== ======== ======== </TABLE> F - 69
NOTES TO FINANCIAL STATEMENTS (Continued) Note 42-- Oil and gas exploration and production activities (a) (continued) <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> 1998 Turnover (d): Third parties........................ 2,481 520 2,027 905 5,933 Sales between businesses............. 1,063 73 2,782 2,133 6,051 -------- -------- -------- -------- -------- 3,544 593 4,809 3,038 11,984 -------- -------- -------- -------- -------- Exploration expense.................... 134 89 240 458 921 Production costs....................... 878 146 1,548 888 3,460 Production taxes....................... 15 6 233 320 574 Other costs (income) (e)............... (50) (18) 780 384 1,096 Depreciation and amounts provided...... 1,183 169 1,168 1,072 3,592 -------- -------- -------- -------- -------- 2,160 392 3,969 3,122 9,643 -------- -------- -------- -------- -------- Profit (loss) before taxation (f)...... 1,384 201 840 (84) 2,341 Allocable taxes........................ 378 79 111 115 683 -------- -------- -------- -------- -------- Results of operations ................. 1,006 122 729 (199) 1,658 ======== ======== ======== ======== ======== </TABLE> - ---------- The Group's share of associated undertakings and joint ventures results of operations in 2000 was a profit of $293 million (1999 $204 million and 1998 $40 million) after deducting a tax charge of $97 million (1999 $6 million tax credit and 1998 $19 million tax credit). The Group's share of associated undertakings and joint ventures net capitalized costs at December 31, 2000 was $3,354 million (December 31, 1999 $1,442 million and December 31, 1998 $2,212 million). The Group's share of associated undertakings and joint ventures costs incurred in 2000 was $1,490 million (1999 $49 million and 1998 $282 million). (a) This note relates to the requirements contained within the UK Statement of Recommended Practice 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'. Midstream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main midstream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The Group's share of associated undertakings and joint venture activities are excluded from the tables and included in the footnotes with the exception of the Abu Dhabi operations which are included in the income and expenditure items above. Profits (losses) on sale of businesses and fixed assets relating to the oil and natural gas exploration and production activities, which have been accounted as exceptional items, are also excluded. (b) Accumulated depreciation consists of depreciation, depletion and amortization related to oil and natural gas producing activities. (c) Exploration and appraisal drilling expenditure and licence acquisition costs are initially capitalized within intangible fixed assets in accordance with the Group's accounting policy. (d) Turnover represents sales of production excluding royalty oil where royalty is payable in kind. (e) Includes cost of royalty oil not taken in kind, property taxes and other government take. F - 70
NOTES TO FINANCIAL STATEMENTS (Continued) Note 42-- Oil and gas exploration and production activities (a) (concluded) (f) The exploration and production total replacement cost operating profit comprises: <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> Year ended December 31, 2000 Exploration and production activities -- Group (as above).............. 3,753 826 4,962 3,441 12,982 -- Associated undertakings....... -- -- -- 390 390 Midstream activities............. 290 -- 152 198 640 -------- -------- -------- -------- -------- Total replacement cost operating profit 4,043 826 5,114 4,029 14,012 ======== ======== ======== ======== ======== Year ended December 31, 1999 Exploration and production activities -- Group (as above).............. 2,094 478 1,835 1,804 6,211 -- Associated undertakings....... -- -- 45 153 198 Midstream activities............. 216 9 256 93 574 -------- -------- -------- -------- -------- Total replacement cost operating profit 2,310 487 2,136 2,050 6,983 ======== ======== ======== ======== ======== Year ended December 31, 1998 Exploration and production activities -- Group (as above).............. 1,384 201 840 (84) 2,341 -- Associated undertakings....... (15) -- 31 5 21 Midstream activities............. 317 3 315 176 811 -------- -------- -------- -------- -------- Total replacement cost operating profit 1,686 204 1,186 97 3,173 ======== ======== ======== ======== ======== </TABLE> Note 43 -- US generally accepted accounting principles The consolidated financial statements of the BP Group are prepared in accordance with UK GAAP which differs in certain respects from US GAAP. The principal differences between US GAAP and UK GAAP for BP Group reporting relate to the following: (a) Group consolidation Investments in entities over which the Group does not exercise control (associates and joint ventures) are accounted for by the equity method. UK GAAP requires the consolidated financial statements to show separately the Group proportion of operating profit or loss, exceptional items, inventory holding gains or losses, interest expense and taxation of associated undertakings and joint ventures. In addition the turnover of joint ventures should be disclosed. For US GAAP the after tax profits or losses (i.e. operating results after exceptional items, inventory holding gains or losses, interest expense and taxation) are included in the income statement as a single line item. UK GAAP requires the Group's share of the gross assets and gross liabilities of joint ventures to be shown on the face of the balance sheet whereas under US GAAP the net investment is included as a single line item. F - 71
NOTES TO FINANCIAL STATEMENTS (Continued) Note 43-- US generally accepted accounting principles (continued) Where the Group conducts activities through a joint arrangement that is not carrying on a trade or business in its own right the Group accounts for its own assets, liabilities and cash flows of the activity measured according to the terms of the arrangement. For the Group this method of accounting applies to certain oil and natural gas activities and undivided interests in pipelines. US GAAP requires these activities to be accounted for by proportional consolidation, which is equivalent to UK GAAP. The following summarizes the reclassifications for associates and joint ventures necessary to accord with US GAAP. <TABLE> <CAPTION> Year ended December 31, 2000 --------------------------------------- As US GAAP reported Reclassification presentation -------- ---------------- ------------ ($ million) <S> <C> <C> <C> Consolidated statement of income Other income................................. 805 1,416 2,221 Share of profits of JVs and associated undertakings 1,600 (1,600) -- Exceptional items before taxation............ 220 (24) 196 Inventory holding gains (losses)............. 728 (229) 499 Interest expense............................. 1,770 (218) 1,552 Taxation..................................... 4,972 (219) 4,753 Profit for the year.......................... 11,870 -- 11,870 </TABLE> <TABLE> <CAPTION> Year ended December 31, 1999 --------------------------------------- As US GAAP reported Reclassification presentation -------- ---------------- ------------ ($ million) <S> <C> <C> <C> Consolidated statement of income Other income................................. 414 1,399 1,813 Share of profits of JVs and associated undertakings 1,158 (1,158) -- Exceptional items before taxation............ (2,280) 1 (2,279) Inventory holding gains (losses)............. 1,728 (547) 1,181 Interest expense............................. 1,316 (201) 1,115 Taxation..................................... 1,880 (104) 1,776 Profit for the year.......................... 5,008 -- 5,008 </TABLE> <TABLE> <CAPTION> Year ended December 31, 1998 --------------------------------------- As US GAAP reported Reclassification presentation -------- ---------------- ------------ ($ million) <S> <C> <C> <C> Consolidated statement of income Other income................................. 709 808 1,517 Share of profits of JVs and associated undertakings 1,347 (1,347) -- Exceptional items before taxation............ 850 (85) 765 Inventory holding gains (losses)............. (1,391) 330 (1,061) Interest expense............................. 1,177 (162) 1,015 Taxation..................................... 1,520 (132) 1,388 Profit for the year.......................... 3,220 -- 3,220 </TABLE> (b) Income statement The income statement prepared under UK GAAP shows sub-totals for replacement cost profit before interest and tax, historical cost profit before interest and tax and profit after taxation. These line items are not recognized under US GAAP. F - 72
NOTES TO FINANCIAL STATEMENTS (Continued) Note 43-- US generally accepted accounting principles (continued) (c) Exceptional items Under UK GAAP certain exceptional items are shown separately on the face of the income statement after operating profit. These items are profits or losses on the sale of businesses and fixed assets and fundamental restructuring charges. Under US GAAP these items are classified as operating income or expenses. (d) Impairment Both UK and US GAAP require that long-lived assets and certain identifiable intangibles to be held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. US GAAP requires, in performing the review for recoverability, the entity to estimate the future cash flows expected to result from the use of the asset and its eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, an impairment loss is recognized. Otherwise, no impairment loss is recognized. Measurement of an impairment loss for long-lived assets and identifiable intangibles that an entity expects to hold and use is based on the fair value of the assets. For UK GAAP to the extent that the carrying amount exceeds the recoverable amount, that is the higher of net realizable value and value in use (fair value) the fixed asset is written down to its recoverable amount. No UK/US GAAP adjustment was required for impairment. (e) Provisions UK GAAP requires provisions for decommissioning, environmental liabilities and onerous contracts to be determined on a discounted basis if the effect of the time value of money is material. Under US GAAP (i) environmental liabilities are discounted only where the timing and amounts of payments are fixed and reliably determinable and (ii) provisions for decommissioning are provided on a unit-of-production basis over field lives. The adjustments for decommissioning expense, interest expense and decommissioning and environmental provisions arise from the differences between the UK and US GAAP bases for determining provisions. (f) Deferred taxation Under the UK GAAP restricted liability method, deferred taxation is only provided where timing differences are expected to reverse in the foreseeable future. Under US GAAP deferred taxation is provided for temporary differences between the financial reporting basis and the tax basis of the Group's assets and liabilities at enacted tax rates. US GAAP requires the recognition of a deferred tax asset or liability for the tax effects of differences between the assigned values and the tax bases of assets acquired and liabilities assumed in a purchase business combination, whereas under UK GAAP no such deferred tax asset or liability is recognized. Under US GAAP the deferred tax asset or liability is amortized over the same period as the assets and liabilities to which it relates. The adjustments for fixed assets, depreciation and deferred taxation arise from the difference between the UK GAAP and US GAAP bases for deferred taxation. F - 73
NOTES TO FINANCIAL STATEMENTS (Continued) Note 43-- US generally accepted accounting principles (continued) (f) Deferred taxation (concluded) At December 31, 2000, the adjustment to the carrying amount of fixed assets was $8,367 million ($1,210 million at December 31, 1999) and the related deferred tax liability $8,336 million ($1,145 million at December 31, 1999). The charge for depreciation in 2000 in respect of these assets was $706 million (1999 $115 million and 1998 $123 million) and the credit for taxation $672 million (1999 $91 million and 1998 $256 million). The UK/US GAAP adjustment for deferred taxation may be summarized as follows: <TABLE> <CAPTION> 2000 1999 ------ ------ ($ million) <S> <C> <C> Increase in provision from restricted liability to gross potential liability 7,862 5,356 Tax liability resulting from business combination............................. 8,336 1,145 Net tax asset on sale and leaseback of Chicago office building, severance costs, and other adjustments...................................... (355) (419) ------ ------ 15,843 6,082 ====== ====== </TABLE> The major components of deferred tax liabilities and assets on a US GAAP basis were as follows: <TABLE> <CAPTION> December 31, ----------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Depreciation.......................................... (21,299) (11,394) Other taxable temporary differences................... (504) (1,733) ------ ------ Total deferred tax liabilities........................ (21,803) (13,127) ------ ------ Petroleum revenue tax................................. 337 332 Decommissioning and other provisions.................. 2,610 2,362 Tax credit and loss carry forward..................... 1,713 1,726 Other deductible temporary differences................ 297 1,141 ------ ------ Gross deferred tax assets............................. 4,957 5,561 Valuation allowance................................... (819) (299) ------ ------ Net deferred tax assets............................... 4,138 5,262 ------ ------ Net deferred tax liability*........................... 17,665 7,865 ====== ====== </TABLE> - ---------- * Primarily noncurrent. F - 74
NOTES TO FINANCIAL STATEMENTS (Continued) Note 43-- US generally accepted accounting principles (continued) (g) Ordinary shares held for future awards to employees Under UK GAAP, Company shares held by an Employee Share Ownership Plan to meet future requirements of employee share schemes are recorded in the balance sheet as Fixed assets -- investments. Under US GAAP, such shares are recorded in the balance sheet as a reduction of shareholders' interest. (h) Sale and leaseback The sale and leaseback of the Amoco building in Chicago, Illinois in 1998 is treated as a sale for UK GAAP whereas for US GAAP it is treated as a financing transaction. A provision was recognized under UK GAAP in 1999 to cover the likely shortfall on rental income from subletting the Chicago office building. As the original sale and leaseback was not treated as a sale for US GAAP the provision has been reversed for US GAAP. Under UK GAAP the profit arising on the sale and operating leaseback of certain railcars in 1999 is taken to income in the period in which the transaction occurs. Under US GAAP this profit is not recognized immediately but amortized over the term of the operating lease. (i) Dividends Under UK GAAP, dividends are recorded in the year in respect of which they are announced or declared by the board of directors to the shareholders. Under US GAAP, dividends are recorded in the period in which dividends are declared. (j) Goodwill The goodwill recognized on the acquisition of ARCO in 2000 for US GAAP is higher than for UK GAAP. The additional deferred tax liability recognized for US GAAP is reflected in a corresponding increase in goodwill. This increase is partly offset by the lower consideration for US GAAP compared with UK GAAP as a result of using BP share prices on different dates to determine the respective considerations. (k) Debt retirement charges Under US GAAP charges arising on the early retirement of debt would be shown as an extraordinary item. Under UK GAAP they are included within interest expense. F - 75
NOTES TO FINANCIAL STATEMENTS (Continued) Note 43-- US generally accepted accounting principles (continued) The following is a summary of the adjustments to profit for the year and to BP shareholders' interest which would be required if US GAAP had been applied instead of UK GAAP: Profit for the year <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million except per share amounts) <S> <C> <C> <C> Profit as reported in the consolidated statement of income 11,870 5,008 3,220 Adjustments: Depreciation charge................................. (766) (81) (76) Decommissioning and environmental expense........... (338) (165) (131) Onerous property leases............................. (42) 133 -- Interest expense.................................... 189 110 124 Sale and leaseback of fixed assets.................. -- (37) (211) Deferred taxation................................... (790) (378) (72) Other............................................... 60 6 (28) ------ ------ ------ Profit for the year as adjusted to accord with US GAAP 10,183 4,596 2,826 Dividend requirements on preference shares............ 2 2 1 ------ ------ ------ Profit for the year applicable to ordinary shares as adjusted to accord with US GAAP..................... 10,181 4,594 2,825 ====== ====== ====== Profit for the year as adjusted: Per ordinary share - cents Basic............................................... 47.05 23.70 14.72 Diluted............................................. 46.74 23.56 14.66 ====== ====== ====== Per American Depositary Share - cents Basic............................................... 282.30 142.20 88.32 Diluted............................................. 280.44 141.36 87.96 ====== ====== ====== </TABLE> BP shareholders' interest <TABLE> <CAPTION> December 31, ----------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> BP shareholders' interest as reported in the consolidated balance sheet 73,416 43,281 Adjustments: Fixed assets.................................................... 8,777 1,237 Ordinary shares held for future awards to employees............. (360) (456) Sale and leaseback of Chicago office building................... (413) (413) Decommissioning and environmental provisions.................... (921) (499) Onerous property leases......................................... 105 139 Deferred taxation............................................... (15,843) (6,082) Fourth quarterly dividend....................................... 1,178 972 Pension liability adjustment.................................... (145) (144) Other........................................................... (128) (197) ------ ------ BP shareholders' interest as adjusted to accord with US GAAP...... 65,666 37,838 ====== ====== </TABLE> F - 76
NOTES TO FINANCIAL STATEMENTS (Continued) Note 43-- US generally accepted accounting principles (continued) Comprehensive income The components of comprehensive income, net of related tax are as follows: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Profit for the period as adjusted to accord with USGAAP 10,183 4,596 2,826 Currency translation differences..................... (2,508) (921) 55 Pension liability adjustment......................... (1) (1) (33) ------ ------ ------ Comprehensive income................................. 7,674 3,674 2,848 ====== ====== ====== </TABLE> Accumulated other comprehensive income at December 31, 2000 comprised currency translation losses of $3,882 million (December 31, 1999 losses $1,374 million) and pension liability adjustments of $145 million (December 31, 1999 $144 million). Consolidated balance sheet Under US GAAP Trade and Other receivables due after one year of $4,610million at December 31, 2000 ($3,455 million at December 31, 1999), included within current assets, would have been classified as noncurrent assets. Borrowing under US Industrial Revenue/Municipal Bonds of $1,671 million (December 31, 1999 $1,376 million) included within current liabilities - falling due within one year would under US GAAP have been classified as noncurrent liabilities. The provision for deferred taxation is primarily in respect of noncurrent items. Consolidated statement of cash flows The Group's financial statements include a consolidated statement of cash flows in accordance with the revised UK Financial Reporting Standard No. 1 (FRS1). The statement prepared under FRS1 presents substantially the same information as that required under FASB Statement of Financial Accounting Standards No. 95 'Statement of Cash Flows' (SFAS 95). Under FRS1 cash flows are presented for (i) operating activities; (ii) dividends from joint ventures; (iii) dividends from associated undertakings; (iv) servicing of finance and returns on investments; (v) taxation; (vi) capital expenditure and financial investment; (vii) acquisitions and disposals; (viii) dividends; (ix) financing; and (x) management of liquid resources. SFAS 95 only requires presentation of cash flows from operating, investing and financing activities. Cash flows under FRS1 in respect of dividends from joint ventures and associated undertakings, taxation and servicing of finance and returns on investments are included within operating activities under SFAS 95. Interest paid includes payments in respect of capitalized interest, which under SFAS 95 are included in capital expenditure under investing activities. Cash flows under FRS1 in respect of capital expenditure and acquisitions and disposals are included in investing activities under SFAS 95. Dividends paid are included within financing activities. All short-term investments are regarded as liquid resources for FRS1. Under SFAS 95 short-term investments with original maturities of three months or less are classified as cash equivalents and aggregated with cash in the cash flow statement. Cash flows in respect of short-term investments with original maturities exceeding three months are included in operating activities. F - 77
NOTES TO FINANCIAL STATEMENTS (Continued) Note 43-- US generally accepted accounting principles (continued) The statement of consolidated cash flows presented in accordance with SFAS 95 is as follows: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Operating activities Profit after taxation................................ 11,962 5,146 3,283 Adjustments to reconcile profit after tax to net cash provided by operating activities: Depreciation and amounts provided.................. 7,449 4,965 5,301 Exploration expenditure written off................ 264 304 373 Share of (profit) losses of joint ventures and associated undertakings less dividends received............. (377) (232) 158 Profit (loss) on sale of businesses and fixed assets (196) 379 (963) Working capital (increase) decrease (a)............ (2,848) (1,877) 380 Other.............................................. (1,650) 215 (39) ------ ------ ------ Net cash provided by operating activities............ 14,604 8,900 8,493 ------ ------ ------ Investing activities Capital expenditures................................. (10,220) (6,314) (9,026) Acquisitions......................................... (6,265) (102) (314) Investment in associated undertakings................ (985) (197) (396) Net investment in joint ventures..................... (218) (750) 708 Proceeds from disposal of assets..................... 11,362 2,441 2,167 ------ ------ ------ Net cash used in investing activities................ (6,326) (4,922) (6,861) ------ ------ ------ Financing activities Proceeds from shares (repurchased) issued............ (2,039) 245 (423) Proceeds from long-term financing.................... 1,680 2,140 2,078 Repayments of long-term financing.................... (2,353) (2,268) (1,208) Net (decrease) increase in short-term debt........... (701) 837 (70) Dividends paid -- Shareholders (4,415) (4,135) (2,408) -- Minority shareholders.............. (24) (151) (130) ------ ------ ------ Net cash used in financing activities................ (7,852) (3,332) (2,161) ------ ------ ------ Currency translation differences relating to cash and cash equivalents............................... (50) 15 (15) ------ ------ ------ Increase (decrease) in cash and cash equivalents..... 376 661 (544) Cash and cash equivalents at beginning of year....... 1,455 794 1,338 ------ ------ ------ Cash and cash equivalents at end of year............. 1,831 1,455 794 ====== ====== ====== - ---------- (a) Working capital: Inventories (increase) decrease.................... (1,449) (1,562) 584 Receivables (increase) decrease.................... (5,501) (3,854) 1,777 Current liabilities (excluding finance debt) increase (decrease).............................. 4,102 3,539 (1,981) ------ ------ ------ (2,848) (1,877) 380 ====== ====== ====== </TABLE> F - 78
NOTES TO FINANCIAL STATEMENTS (Continued) Note 43-- US generally accepted accounting principles (concluded) Impact of new accounting standards Derivative instruments and hedging activities: In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133 `Accounting for Derivative Instruments and Hedging Activities (`SFAS 133'). The effective date of this standard was delayed for one year, to accounting periods beginning after June 15, 2000, by Statement of Financial Accounting Standards No.137, `Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 - an amendment of FASB Statement No.133', issued in June 1999. SFAS 133 was further amended in June 2000 by the issuance of Statement of Financial Accounting Standards No. 138, `Accounting for Certain Derivative Instruments and Certain Hedging Activities - an amendment of SFAS 133'. SFAS 133, as amended, requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. To the extent certain criteria are met, SFAS 133 permits, but does not require, hedge accounting. The Group's accounting policies under UK GAAP do not satisfy the criteria for hedge accounting under SFAS 133. The Group does not intend to modify its practice under UK GAAP. All oil price derivatives and all derivatives held for trading are currently carried on the Group's balance sheet at fair value with changes in that value recognized in earnings of the period. For those derivative instruments, there will be no impact of adopting SFAS 133 on the Group's results of operations and financial position, as adjusted to accord with US GAAP. Certain derviatives used to manage foreign currency risk and interest rate risk that qualify for hedge accounting under UK GAAP will be marked to market under SFAS 133. For those derivative instruments, the Company estimates that the cumulative effect adjustment on adoption of SFAS 133 would be an after-tax charge to the income statement, as adjusted to accord with US GAAP, of $18 million and an after-tax gain in other comprehensive income of $37 million. Changes in the fair value of those derivatives in subsequent periods could result in increased volatility of results of operations, as adjusted to accord with US GAAP. Because the Company does not intend to modify its accounting practice to satisfy the criteria for hedge accounting under SFAS 133, the Group's results of operations, as adjusted to accord with US GAAP, will not necessarily be representative of the results it would report if US GAAP were used to prepare the consolidated financial statements of the BP Group and the Group sought to meet the hedge criteria of SFAS 133. Retirement benefits: In December 2000, the UK Accounting Standards Board issued Financial Reporting Standard No.17 `Retirement Benefits' (`FRS17'). This standard is fully effective for accounting periods ending on or after June 22, 2003. Certain of the disclosure requirements are effective for periods prior to 2003. FRS17 requires that financial statements reflect at fair value the assets and liabilities arising from an employer's retirement benefit obligations and any related funding. The operating costs of providing retirement benefits are recognized in the period in which they are earned together with any related finance costs and changes in the value of related assets and liabilities. The Company has not yet completed its evaluation of the impact of adopting FRS17 on the Group's results of operations and financial position. Accounting policies: In December 2000, the UK Accounting Standards Board issued Financial Reporting Standard No. 18 `Accounting Policies' (`FRS18'). The standard sets out the principles to be followed in selecting accounting policies and the disclosures required. FRS18 is effective for accounting periods ending on or after June 22, 2001. Adoption of the standard will have no impact on the Group's results of operations or financial position. Deferred taxation: In December 2000, the UK Accounting Standards Board issued Financial Reporting Standard No.19 `Deferred Tax' (`FRS19'). The standard requires that deferred tax should be provided in full on most timing differences. FRS19 permits, but does not require, discounting of deferred tax assets and liabilities. The standard is effective for accounting periods ending on or after January 23, 2002. The Company has not yet completed its evaluation of the impact of FRS19 on the Group's results of operations and financial position. F - 79
Note 44 -- Business and geographical analysis BP has four reportable operating segments -- Exploration and Production, Gas and Power, Refining and Marketing and Chemicals. Exploration and Production's activities include oil and natural gas exploration and field development and production (upstream activities), together with pipeline transportation and natural gas processing (midstream activities). Gas and Power activities include marketing and trading of natural gas, liquefied natural gas, natural gas liquids and power, the development of international opportunties that monetize upstream gas resources and involvement in select power projects. The activities of Refining and Marketing include oil supply and trading as well as refining and marketing (downstream activities). Chemicals activities include petrochemicals manufacturing and marketing. The Group is managed on a unified basis. Reportable segments are differentiated by the activities that each undertakes and the products they manufacture and market. The accounting policies of operating segments are the same as those described in Note 1, Accounting Policies. Performance is evaluated based on replacement cost operating profit or loss, which excludes exceptional items, inventory holding gains and losses, interest income and expense, taxation and minority shareholders' interests. Sales between segments are made at prices that approximate market prices taking into account the volumes involved. F - 80
NOTES TO FINANCIAL STATEMENTS (Continued) Note 44-- Business and geographical analysis (continued) By business <TABLE> <CAPTION> Other Exploration Gas Refining business and and and and Production Power Marketing Chemicals corporate(a) Eliminations Total ----------- ----- --------- --------- --------- ------------ ----- ($ million) 2000 <S> <C> <C> <C> <C> <C> <C> <C> Group turnover -- third parties..... 14,155 15,735 106,892 11,031 249 -- 148,062 -- sales between businesses (b)... 16,787 346 5,923 216 -- (23,272) -- ------ ------ ------- ------ ------- ------- ------ 30,942 16,081 112,815 11,247 249 (23,272) 148,062 ------ ------ ------- ------ ------- ------- Share of joint venture sales........ 13,764 ------- 161,826 ------- Equity accounted income (c)......... 613 162 599 184 42 1,600 ------ ------ ------- ------ ------- ------- Total replacement cost operating profit (loss) (d)................. 14,012 186 3,908 760 (1,110) 17,756 Exceptional items (e)............... 119 -- 99 (212) 214 220 Inventory holding gains (losses).... 4 11 620 93 -- 728 ------ ------ ------- ------ ------- ------- Historical cost profit (loss) before interest and tax.................. 14,135 197 4,627 641 (896) 18,704 ------ ------ ------- ------ ------- ------- Total assets (f).................... 65,904 4,511 47,879 13,674 11,970 143,938 Operating capital employed (g)...... 56,500 1,735 29,066 11,008 1,486 99,795 Depreciation and amounts provided (h) 5,156 6 1,756 704 91 7,713 Capital expenditure and acquisitions (i) 6,383 279 8,750 1,585 30,616 47,613 1999 Group turnover -- third parties..... 9,070 4,879 60,369 9,050 198 -- 83,566 -- sales between businesses (b)... 10,063 444 2,524 342 -- (13,373) -- ------ ------ ------- ------ ------- ------- ------ 19,133 5,323 62,893 9,392 198 (13,373) 83,566 ------ ------ ------- ------ ------- ------- Share of joint venture sales........ 17,614 ------- 101,180 ------- Equity accounted income (c)......... 297 179 503 125 54 1,158 ------ ------ ------- ------ ------- ------- Total replacement cost operating profit (loss) (d)................. 6,983 211 1,840 686 (826) 8,894 Exceptional items (e)............... (1,111) 14 (334) (257) (592) (2,280) Inventory holding gains (losses).... (1) -- 1,613 116 -- 1,728 ------ ------ ------- ------ ------- ------- Historical cost profit (loss) before interest and tax.................. 5,871 225 3,119 545 (1,418) 8,342 ------ ------ ------- ------ ------- ------- Total assets (f).................... 44,967 1,682 27,248 13,021 2,643 89,561 Operating capital employed (g)...... 36,229 1,093 14,358 10,048 1,192 62,920 Depreciation and amounts provided (h) 3,704 1 810 632 206 5,353 Capital expenditure and acquisitions (i) 4,194 18 1,634 1,215 284 7,345 </TABLE> F - 81
NOTES TO FINANCIAL STATEMENTS (Continued) Note 44-- Business and geographical analysis (continued) <TABLE> <CAPTION> Other Exploration Gas Refining business and and and and Production Power Marketing Chemicals corporate(a) Eliminations Total ----------- ----- --------- --------- --------- ------------ ----- ($ million) 1998 <S> <C> <C> <C> <C> <C> <C> <C> Group turnover -- third parties..... 7,416 4,800 46,625 9,312 151 -- 68,304 -- sales between businesses (b)... 8,664 -- 1,812 379 48 (10,903) -- ------ ------ ------- ------ ------- ------- ------ 16,080 4,800 48,437 9,691 199 (10,903) 68,304 ------ ------ ------- ------ ------- ------- Share of joint venture sales........ 15,428 ------- 83,732 ------- Equity accounted income (c)......... 87 157 852 150 101 1,347 ------ ------ ------- ------ ------- ------- Total replacement cost operating profit (loss) (d)................. 3,173 58 2,564 1,100 (374) 6,521 Exceptional items (e)............... 380 16 394 43 17 850 Inventory holding gains (losses).... (17) -- (1,228) (146) -- (1,391) ------ ------ ------- ------ ------- ------- Historical cost profit (loss) before interest and tax.................. 3,536 74 1,730 997 (357) 5,980 ------ ------ ------- ------ ------- ------- Total assets (f).................... 46,194 1,614 21,029 12,562 3,516 84,915 Operating capital employed (g)...... 37,537 1,282 12,563 10,178 (579) 60,981 Depreciation and amounts provided (h) 4,271 1 790 497 115 5,674 Capital expenditure and acquisitions (i) 6,223 95 1,937 1,606 501 10,362 </TABLE> By geographical area <TABLE> <CAPTION> United Rest of Rest of Kingdom(j) Europe USA World Eliminations Total ---------- --------- --------- ---------- ------------ ----- ($ million) <S> <C> <C> <C> <C> <C> <C> 2000 Group turnover -- third parties (k)...... 34,430 18,642 70,255 24,735 148,062 -- sales between areas.... 15,970 2,911 2,629 6,279 (27,789) -- ------- ------- ------- ------- ------- ------- 50,400 21,553 72,884 31,014 (27,789) 148,062 ------- ------- ------- ------- ------- Share of joint venture sales............ 3,314 12,316 270 686 (2,822) 13,764 ------- 161,826 ------- Equity accounted income (c)............. 144 525 290 641 1,600 ------- ------- ------- ------- ------- Total replacement cost operating profit (d) ................ 3,773 2,013 7,296 4,674 17,756 Exceptional items (e)........ 12 (19) 459 (232) 220 Inventory holding gains (losses) 103 107 387 131 728 ------- ------- ------- ------- ------- Historical cost profit before interest and tax........... 3,888 2,101 8,142 4,573 18,704 ------- ------- ------- ------- ------- Total assets (f)............. 35,713 14,584 62,141 31,500 143,938 Operating capital employed (g) 20,093 7,087 43,758 28,857 99,795 Capital expenditure and acquisitions (i) 7,438 2,041 34,037 4,097 47,613 </TABLE> F - 82
NOTES TO FINANCIAL STATEMENTS (Continued) Note 44-- Business and geographical analysis (continued) <TABLE> <CAPTION> United Rest of Rest of Kingdom(j) Europe USA World Eliminations Total ---------- --------- --------- ---------- ------------ ----- ($ million) <S> <C> <C> <C> <C> <C> <C> 1999 Group turnover -- third parties (k)...... 25,817 5,332 37,405 15,012 83,566 -- sales between areas.... 4,406 641 1,381 4,453 (10,881) -- ------- ------- ------- ------- ------- ------- 30,223(k) 5,973(k) 38,786 19,465 (10,881) 83,566 ------- ------- ------- ------- ------- Share of joint venture sales............ 3,988 16,114 155 342 (2,985) 17,614 ------- 101,180 ------- Equity accounted income (c)............. 48 619 198 293 1,158 ------- ------- ------- ------- ------- Total replacement cost operating profit (d) ................ 2,111 1,167 3,001 2,615 8,894 Exceptional items (e)........ (237) (258) (983) (802) (2,280) Inventory holding gains (losses) 151 494 839 244 1,728 ------- ------- ------- ------- ------- Historical cost profit before interest and tax........... 2,025 1,403 2,857 2,057 8,342 ------- ------- ------- ------- ------- Total assets (f)............. 22,867 8,865 38,223 19,606 89,561 Operating capital employed (g) 14,298 4,884 27,426 16,312 62,920 Capital expenditure and acquisitions (i) 1,518 831 2,963 2,033 7,345 1998 Group turnover -- third parties (k)...... 19,662 5,123 31,945 11,574 68,304 -- sales between areas.... 2,848 700 1,215 2,458 (7,221) -- ------- ------- ------- ------- ------- ------- 22,510(k) 5,823(k) 33,160 14,032 (7,221) 68,304 ------- ------- ------- ------- ------- Share of joint venture sales............ 3,467 14,186 43 305 (2,573) 15,428 ------- 83,732 ------- Equity accounted income (c)............. 135 904 125 183 1,347 ------- ------- ------- ------- ------- Total replacement cost operating profit (d) ................ 1,931 1,249 2,631 710 6,521 Exceptional items (e)........ (39) 106 511 272 850 Inventory holding gains (losses) (136) (283) (720) (252) (1,391) ------- ------- ------- ------- ------- Historical cost profit before interest and tax........... 1,756 1,072 2,422 730 5,980 ------- ------- ------- ------- ------- Total assets (f)............. 22,747 8,538 35,823 17,807 84,915 Operating capital employed (g) 14,188 5,053 26,629 15,111 60,981 Capital expenditure and acquisitions (i) 2,463 1,248 3,720 2,931 10,362 </TABLE> - ---------- (a) Other businesses and corporate comprises Finance, BP Solar, the Group's coal asset and aluminium asset, its investment in PetroChina and Sinopec, interest income and costs relating to corporate activities worldwide. (b) Sales and transfers between businesses are made at market prices taking into account the volumes involved. (c) Equity accounted income (loss) represents the Group's share of income (loss) before interest expense and taxes of joint ventures and associated undertakings. (d) Total replacement cost operating profit (loss) is before inventory holding gains and losses and interest expense, which is attributable to the corporate function. F - 83
NOTES TO FINANCIAL STATEMENTS (Continued) Note 44-- Business and geographical analysis (concluded) (e) Exceptional items comprise profit on sale of businesses and sale of fixed assets of $220 million in 2000 (1999 $337 million loss and 1998 $1,048 million profit), restructuring costs in 1999 of $1,943 million and merger expenses in 1998 of $198 million. (f) Total assets comprise fixed and current assets and include investments in joint ventures and associated undertakings analyzed between activities as follows: <TABLE> <CAPTION> Other Exploration Gas Refining businesses and and and and Production Power Marketing Chemicals corporate(a) Total ---------- ----- --------- --------- ---------- ----- ($ million) <S> <C> <C> <C> <C> <C> <C> 2000...................... 5,093 744 1,220 1,155 127 8,339 ----- ----- ----- ----- ----- ----- 1999...................... 2,550 762 4,771 1,350 105 9,538 ----- ----- ----- ----- ----- ----- 1998...................... 2,588 828 4,345 1,281 125 9,167 ----- ----- ----- ----- ----- ----- </TABLE> (g) Operating capital employed comprises net assets before deducting finance debt and liabilities for current and deferred taxation. (h) Depreciation consists of charges for depreciation, depletion and amortization of property, plant and equipment, exploration expense and amounts provided against fixed asset investments. (i) Capital expenditure and acquisitions includes $170 million in 2000 (1999 $624 million and 1998 $620 million) for the BP/Mobil joint venture. (j) United Kingdom area includes the UK-based international activities of Refining and Marketing. (k) Turnover to third parties is stated by origin which is not materially different from turnover by destination. Note 45-- Summarized financial information on associated undertakings and joint ventures A summarized statement of income and assets and liabilities based on latest information available, with respect to the Group's equity accounted associated undertakings and joint ventures, is set out below: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and other operating revenue.................... 42,425 41,180 42,801 Gross profit......................................... 7,358 7,715 7,484 Profit for the year.................................. 2,609 2,641 675 ====== ====== ====== </TABLE> <TABLE> <CAPTION> December 31, ----------------- 2000 1999 ------ ------ ($ million) <S> <C> <C> Fixed and other assets............................... 24,893 17,398 Current assets....................................... 12,606 12,232 ------ ------ 37,499 29,630 Current liabilities.................................. (9,271) (10,929) Noncurrent liabilities............................... (10,628) (5,876) ------ ------ Net assets........................................... 17,600 12,825 ====== ====== </TABLE> - ---------- F - 84
NOTES TO FINANCIAL STATEMENTS (Continued) Note 45-- Summarized financial information on associated undertakings and joint ventures (concluded) The more important associated undertakings and joint ventures of the Group at December 31, 2000 and the percentage of equity capital owned or joint venture interest are: <TABLE> <CAPTION> % Country of operation Principal activities -- -------------------- -------------------- <S> <C> <C> <C> Associated undertakings Abu Dhabi Marine Areas........................... 33 Abu Dhabi Crude oil production Abu Dhabi Petroleum.............................. 24 Abu Dhabi Crude oil production China American Petroleum Co...................... 50 Taiwan Chemicals Erdolchemie...................................... 50 Germany Chemicals Ruhrgas.......................................... 25 Germany Gas distribution Rusia............................................ 25 Russia Exploration and production Sidanco (a)...................................... 10 Russia Integrated oil operations Joint ventures CaTo Finance Partnership......................... 50 UK Finance Empresa Petrolera Chaco.......................... 30 Bolivia Exploration and production Lukarco.......................................... 46 Kazakhstan Exploration and production, pipelines Malaysia - Thailand Joint Development Area....... 25 Thailand Exploration and production Pan American Energy.............................. 60 Argentina Exploration and production Unimar Company Texas (Partnership)............... 50 Indonesia Exploration and production </TABLE> - ---------- (a) 20% voting interest. F - 85
NOTES TO FINANCIAL STATEMENTS (Continued) Note 46-- Condensed consolidating information on certain US Subsidiaries BP Amoco p.l.c. fully and unconditionally guarantees certain publicly issued debt of its 100% owned subsidiary BP America Inc. BP Amoco p.l.c. also fully and unconditionally guarantees the payment obligations of its 100% owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The following financial information for BP Amoco p.l.c., BP America Inc. and BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP Amoco p.l.c. and its subsidiary issuers of debt securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt securities. Investments include the investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating financial information. Equity income of subsidiaries is the Group's share of replacement cost operating profit related to such investments. The eliminations and reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP Amoco p.l.c., BP America Inc., BP Exploration (Alaska) Inc. and other subsidiaries. Income statement <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 2000 Turnover .................... -- 2,665 -- 161,826 (2,665) 161,826 Less: Joint ventures......... -- -- -- 13,764 -- 13,764 ------- ------- ------- ------- ------- ------- Group turnover............... -- 2,665 -- 148,062 (2,665) 148,062 Replacement cost of sales.... -- 1,126 -- 123,162 (2,772) 121,516 Production taxes............. -- 276 -- 1,785 -- 2,061 ------- ------- ------- ------- ------- ------- Gross profit................. -- 1,263 -- 23,115 107 24,485 Distribution and administration expenses.................... -- 25 603 7,907 -- 8,535 Exploration expense.......... -- 26 -- 573 -- 599 ------- ------- ------- ------- ------- ------- -- 1,212 (603) 14,635 107 15,351 Other income................. 21 (12) 545 791 (540) 805 ------- ------- ------- ------- ------- ------- Group replacement cost operating profit............ 21 1,200 (58) 15,426 (433) 16,156 Share of profits of joint ventures -- -- -- 808 -- 808 Share of profits of associated undertakings -- -- -- 792 -- 792 Equity accounted income of subsidiaries 12,730 282 18,155 -- (31,167) -- ------- ------- ------- ------- ------- ------- Total replacement cost operating profit............ 12,751 1,482 18,097 17,026 (31,600) 17,756 Profit (loss) on sale of businesses (11) -- 26,049 (90) (25,816) 132 Profit (loss) on sale of fixed assets 452 (1) 88 111 (562) 88 ------- ------- ------- ------- ------- ------- Replacement cost profit before interest and tax..... 13,192 1,481 44,234 17,047 (57,978) 17,976 Inventory holding gains (losses) 438 (6) 728 728 (1,160) 728 ------- ------- ------- ------- ------- ------- Historical cost profit before interest and tax..... 13,630 1,475 44,962 17,775 (59,138) 18,704 Interest expense............. 1,338 22 2,203 2,201 (3,994) 1,770 ------- ------- ------- ------- ------- ------- Profit before taxation....... 12,292 1,453 42,759 15,574 (55,144) 16,934 Taxation .................... 3,513 552 4,972 4,699 (8,764) 4,972 ------- ------- ------- ------- ------- ------- Profit after taxation........ 8,779 901 37,787 10,875 (46,380) 11,962 Minority shareholders' interest -- -- -- 92 -- 92 ------- ------- ------- ------- ------- ------- Profit for the year.......... 8,779 901 37,787 10,783 (46,380) 11,870 ======= ======= ======= ======= ======= ======= </TABLE> F - 86
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) The following is a summary of the adjustments to the profit for the period which would be required if generally accepted accounting principles in the United States (US GAAP) had been applied instead of those generally accepted in the United Kingdom. <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 2000 Profit as reported.......... 8,779 901 37,787 10,783 (46,380) 11,870 Adjustments: Depreciation charge......... (699) (54) (766) (714) 1,467 (766) Decommissioning and environmental expense (156) (31) (338) (307) 494 (338) Onerous property leases..... (42) -- (42) (42) 84 (42) Interest expense............ 127 9 189 180 (316) 189 Sale and leaseback of fixed assets 3 -- -- -- (3) -- Deferred taxation........... (854) 10 (790) (684) 1,528 (790) Other....................... -- -- 60 60 (60) 60 ------- ------- ------- ------- ------- ------- Profit for the year as adjusted to accord with US GAAP......... 7,158 835 36,100 9,276 (43,186) 10,183 ======= ======= ======= ======= ======= ======= </TABLE> F - 87
NOTES TO FINANCIAL STATEMENTS (Continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Income statement <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 1999 Turnover .................... -- 2,065 -- 101,180 (2,065) 101,180 Less: Joint ventures......... -- -- -- 17,614 -- 17,614 ------- ------- ------- ------- ------- ------- Group turnover............... -- 2,065 -- 83,566 (2,065) 83,566 Replacement cost of sales.... -- 1,487 -- 69,214 (2,086) 68,615 Production taxes............. -- 272 -- 745 -- 1,017 ------- ------- ------- ------- ------- ------- Gross profit................. -- 306 -- 13,607 21 13,934 Distribution and administration expenses.................... 65 36 473 5,490 -- 6,064 Exploration expense.......... -- 22 -- 526 -- 548 ------- ------- ------- ------- ------- ------- (65) 248 (473) 7,591 21 7,322 Other income................. 2 -- 465 410 (463) 414 ------- ------- ------- ------- ------- ------- Group replacement cost operating profit............ (63) 248 (8) 8,001 (442) 7,736 Share of profits of joint ventures -- -- -- 555 -- 555 Share of profits of associated undertakings -- -- -- 603 -- 603 Equity accounted income of subsidiaries 5,555 134 9,206 -- (14,895) -- ------- ------- ------- ------- ------- ------- Total replacement cost operating profit............ 5,492 382 9,198 9,159 (15,337) 8,894 Profit (loss) on sale of businesses 2 -- 356 339 (334) 363 Profit (loss) on sale of fixed assets 252 -- (700) (700) 448 (700) Restructuring costs.......... (1,263) (61) (1,943) (1,799) 3,123 (1,943) ------- ------- ------- ------- ------- ------- Replacement cost profit before interest and tax..... 4,483 321 6,911 6,999 (12,100) 6,614 Inventory holding gains (losses) 859 40 1,728 1,728 (2,627) 1,728 ------- ------- ------- ------- ------- ------- Historical cost profit before interest and tax..... 5,342 361 8,639 8,727 (14,727) 8,342 Interest expense............. 985 41 1,758 1,741 (3,209) 1,316 ------- ------- ------- ------- ------- ------- Profit before taxation....... 4,357 320 6,881 6,986 (11,518) 7,026 Taxation .................... 803 78 1,880 1,775 (2,656) 1,880 ------- ------- ------- ------- ------- ------- Profit after taxation........ 3,554 242 5,001 5,211 (8,862) 5,146 Minority shareholders' interest -- -- -- 138 -- 138 ------- ------- ------- ------- ------- ------- Profit for the year.......... 3,554 242 5,001 5,073 (8,862) 5,008 ======= ======= ======= ======= ======= ======= </TABLE> F - 88
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) The following is a summary of the adjustments to the profit for the period which would be required if generally accepted accounting principles in the United States (US GAAP) had been applied instead of those generally accepted in the United Kingdom. <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 1999 Profit as reported.......... 3,554 242 5,001 5,073 (8,862) 5,008 Adjustments: Depreciation charge......... (71) (59) (81) (23) 153 (81) Decommissioning and environmental expense (13) 13 (165) (178) 178 (165) Onerous property leases..... 133 -- 133 133 (266) 133 Interest expense............ 68 11 110 99 (178) 110 Sale and leaseback of fixed assets (37) -- (37) (37) 74 (37) Deferred taxation........... (79) 79 (378) (422) 422 (378) Other....................... -- -- 6 6 (6) 6 ------- ------- ------- ------- ------- ------- Profit for the year as adjusted to accord with US GAAP......... 3,555 286 4,589 4,651 (8,485) 4,596 ======= ======= ======= ======= ======= ======= </TABLE> F - 89
NOTES TO FINANCIAL STATEMENTS (Continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Income statement <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 1998 Turnover .................... -- 1,702 -- 83,732 (1,702) 83,732 Less: Joint ventures......... -- -- -- 15,428 -- 15,428 ------- ------- ------- ------- ------- ------- Group turnover............... -- 1,702 -- 68,304 (1,702) 68,304 Replacement cost of sales.... -- 1,328 -- 56,735 (1,793) 56,270 Production taxes............. -- 241 -- 363 -- 604 ------- ------- ------- ------- ------- ------- Gross profit................. -- 133 -- 11,206 91 11,430 Distribution and administration expenses.................... 9 5 255 5,775 -- 6,044 Exploration expense.......... -- 17 -- 904 -- 921 ------- ------- ------- ------- ------- ------- (9) 111 (255) 4,527 91 4,465 Other income................. 6 (4) 556 707 (556) 709 ------- ------- ------- ------- ------- ------- Group replacement cost operating profit............ (3) 107 301 5,234 (465) 5,174 Share of profits of joint ventures -- -- -- 825 -- 825 Share of profits of associated undertakings -- -- -- 522 -- 522 Equity accounted income of subsidiaries 3,024 (23) 6,622 -- (9,623) -- ------- ------- ------- ------- ------- ------- Total replacement cost operating profit............ 3,021 84 6,923 6,581 (10,088) 6,521 Profit (loss) on sale of businesses (1) -- 395 396 (395) 395 Profit (loss) on sale of fixed assets 636 -- 653 653 (1,289) 653 Merger expenses.............. (119) -- (198) (119) 238 (198) ------- ------- ------- ------- ------- ------- Replacement cost profit before interest and tax..... 3,537 84 7,773 7,511 (11,534) 7,371 Inventory holding gains (losses) (767) (96) (1,391) (1,390) 2,253 (1,391) ------- ------- ------- ------- ------- ------- Historical cost profit before interest and tax..... 2,770 (12) 6,382 6,121 (9,281) 5,980 Interest expense............. 960 27 1,642 1,627 (3,079) 1,177 ------- ------- ------- ------- ------- ------- Profit before taxation....... 1,810 (39) 4,740 4,494 (6,202) 4,803 Taxation .................... 553 21 1,520 1,522 (2,096) 1,520 ------- ------- ------- ------- ------- ------- Profit after taxation........ 1,257 (60) 3,220 2,972 (4,106) 3,283 Minority shareholders' interest -- -- -- 63 -- 63 ------- ------- ------- ------- ------- ------- Profit for the year.......... 1,257 (60) 3,220 2,909 (4,106) 3,220 ======= ======= ======= ======= ======= ======= </TABLE> F - 90
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) The following is a summary of the adjustments to the profit for the period which would be required if generally accepted accounting principles in the United States (US GAAP) had been applied instead of those generally accepted in the United Kingdom. <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 1998 Profit as reported.......... 1,257 (60) 3,220 2,909 (4,106) 3,220 Adjustments: Depreciation charge......... (65) (46) (76) (32) 143 (76) Decommissioning and environmental expense (30) -- (131) (131) 161 (131) Interest expense............ 87 4 124 120 (211) 124 Sale and leaseback of fixed assets (211) -- (211) (211) 422 (211) Deferred taxation........... (322) (64) (72) 83 303 (72) Other....................... -- -- (28) (28) 28 (28) ------- ------- ------- ------- ------- ------- Profit for the year as adjusted to accord with US GAAP......... 716 (166) 2,826 2,710 (3,260) 2,826 ======= ======= ======= ======= ======= ======= </TABLE> F - 91
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Balance sheet <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> At December 31, 2000 Fixed assets Intangible assets............ -- 512 -- 16,381 -- 16,893 Tangible assets.............. 7 5,942 -- 69,224 -- 75,173 Investments Joint ventures............ -- -- -- 2,884 -- 2,884 Associated undertakings... -- -- 3 5,452 -- 5,455 Other..................... -- -- 360 3,054 -- 3,414 Subsidiaries - equity accounted basis 63,718 619 77,826 -- (142,163) -- ------- ------- ------- ------- ------- ------- 63,718 619 78,189 11,390 (142,163) 11,753 ------- ------- ------- ------- ------- ------- Total fixed assets........... 63,725 7,073 78,189 96,995 (142,163) 103,819 ------- ------- ------- ------- ------- ------- Current assets Business held for resale..... -- -- -- 636 -- 636 Inventories.................. -- 75 -- 9,159 -- 9,234 Receivables - amounts falling due: Within one year........... 1,135 1,344 3,929 23,086 (5,686) 23,808 After more than one year.. 5,872 8,689 19,466 5,782 (35,199) 4,610 Investments.................. -- -- -- 661 -- 661 Cash at bank and in hand..... (2) (32) 2 1,202 -- 1,170 ------- ------- ------- ------- ------- ------- 7,005 10,076 23,397 40,526 (40,885) 40,119 ------- ------- ------- ------- ------- ------- Current liabilities - amounts falling due within one year Finance debt................. 6,848 -- -- 6,418 (6,848) 6,418 Other payables............... 85 973 2,582 35,556 (8,467) 30,729 ------- ------- ------- ------- ------- ------- Net current assets (liabilities) 72 9,103 20,815 (1,448) (25,570) 2,972 ------- ------- ------- ------- ------- ------- Total assets less current liabilities 63,797 16,176 99,004 95,547 (167,733) 106,791 Noncurrent liabilities Finance debt................. -- 1,150 -- 14,772 (1,150) 14,772 Other payables............... 1,099 4,275 178 24,091 (24,420) 5,223 Provisions for liabilities and charges Deferred taxation............ -- (5) -- 1,827 -- 1,822 Other........................ 49 269 197 10,458 -- 10,973 ------- ------- ------- ------- ------- ------- Net assets................... 62,649 10,487 98,629 44,399 (142,163) 74,001 Minority shareholders' interest - equity -- -- -- 585 -- 585 ------- ------- ------- ------- ------- ------- BP Shareholders' interest.... 62,649 10,487 98,629 43,814 (142,163) 73,416 ======= ======= ======= ======= ======= ======= </TABLE> F - 92
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Balance sheet (continued) <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> At December 31, 2000 Capital and reserves Capital shares............... 8 -- 5,653 -- (8) 5,653 Paid in surplus.............. 30,440 3,145 3,770 -- (33,585) 3,770 Merger reserve............... -- -- 26,172 697 -- 26,869 Other reserves............... -- -- 456 -- -- 456 Retained earnings............ 32,201 7,342 62,578 43,117 (108,570) 36,668 ------- ------- ------- ------- ------- ------- 62,649 10,487 98,629 43,814 (142,163) 73,416 ======= ======= ======= ======= ======= ======= </TABLE> The following is a summary of the adjustments to BP shareholders' interest which would be required if generally accepted accounting principles in the United States (US GAAP) had been applied instead of those generally accepted in the United Kingdom. <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> Shareholders' interest as reported 62,649 10,487 98,629 43,814 (142,163) 73,416 Adjustments: Fixed assets................ 8,757 566 8,777 8,215 (17,538) 8,777 Ordinary shares held for future awards to employees........ -- -- (360) -- -- (360) Sale and leaseback of Chicago office building............ (413) -- (413) (413) 826 (413) Decommissioning and environmental provisions... (927) (317) (921) (586) 1,830 (921) Onerous property leases..... 105 -- 105 105 (210) 105 Deferred taxation........... (14,805) (1,784) (15,843) (14,168) 30,757 (15,843) Fourth quarterly dividend... -- -- 1,178 -- -- 1,178 Pension liability adjustment (38) -- (145) (145) 183 (145) Other....................... (34) -- (128) (128) 162 (128) ------- ------- ------- ------- ------- ------- Shareholders' interest as adjusted to accord with US GAAP...... 55,294 8,952 90,879 36,694 (126,153) 65,666 ======= ======= ======= ======= ======= ======= </TABLE> F - 93
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Balance sheet <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> At December 31, 1999 Fixed assets Intangible assets............ -- 185 -- 3,159 -- 3,344 Tangible assets.............. 37 6,144 -- 46,450 -- 52,631 Investments Joint ventures............ -- -- -- 5,204 -- 5,204 Associated undertakings... -- -- 3 4,331 -- 4,334 Other..................... -- -- 456 115 -- 571 Subsidiaries - equity accounted basis 28,565 504 34,191 -- (63,260) -- ------- ------- ------- ------- ------- ------- 28,565 504 34,650 9,650 (63,260) 10,109 ------- ------- ------- ------- ------- ------- Total fixed assets........... 28,602 6,833 34,650 59,259 (63,260) 66,084 ------- ------- ------- ------- ------- ------- Current assets Inventories.................. -- 81 -- 5,043 -- 5,124 Receivables - amounts falling due: Within one year........... 146 1,350 6,588 11,900 (6,637) 13,347 After more than one year.. 7,069 8,988 2,645 4,644 (19,891) 3,455 Investments.................. -- -- -- 220 -- 220 Cash at bank and in hand..... (3) (18) 3 1,349 -- 1,331 ------- ------- ------- ------- ------- ------- 7,212 10,401 9,236 23,156 (26,528) 23,477 ------- ------- ------- ------- ------- ------- Current liabilities - amounts falling due within one year Finance debt................. 8,090 -- -- 4,900 (8,090) 4,900 Other payables............... 28 1,635 1,076 25,135 (9,499) 18,375 ------- ------- ------- ------- ------- ------- Net current assets (liabilities) (906) 8,766 8,160 (6,879) (8,939) 202 ------- ------- ------- ------- ------- ------- Total assets less current liabilities 27,696 15,599 42,810 52,380 (72,199) 66,286 Noncurrent liabilities Finance debt................. -- 1,150 -- 9,644 (1,150) 9,644 Other payables............... 1,141 4,516 62 4,315 (7,789) 2,245 Provisions for liabilities and charges Deferred taxation............ 112 (8) -- 1,679 -- 1,783 Other........................ -- 355 171 7,746 -- 8,272 ------- ------- ------- ------- ------- ------- Net assets................... 26,443 9,586 42,577 28,996 (63,260) 44,342 Minority shareholders' interest - equity -- -- -- 1,061 -- 1,061 ------- ------- ------- ------- ------- ------- BP Shareholders' interest.... 26,443 9,586 42,577 27,935 (63,260) 43,281 ======= ======= ======= ======= ======= ======= </TABLE> F - 94
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Balance sheet (continued) <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> At December 31, 1999 Capital and reserves Capital shares............... 6 -- 4,892 -- (6) 4,892 Paid in surplus.............. 3,015 3,145 3,684 -- (6,160) 3,684 Merger reserve............... -- -- -- 697 -- 697 Retained earnings............ 23,422 6,441 34,001 27,238 (57,094) 34,008 ------- ------- ------- ------- ------- ------- 26,443 9,586 42,577 27,935 (63,260) 43,281 ======= ======= ======= ======= ======= ======= </TABLE> The following is a summary of the adjustments to BP shareholders' interest which would be required if generally accepted accounting principles in the United States (US GAAP) had been applied instead of those generally accepted in the United Kingdom. <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> Shareholders' interest as reported 26,443 9,586 42,577 27,935 (63,260) 43,281 Adjustments: Fixed assets................ 1,269 850 1,237 409 (2,528) 1,237 Ordinary shares held for future awards to employees........ -- -- (456) -- -- (456) Sale and leaseback of Chicago office building............ (413) -- (413) (413) 826 (413) Decommissioning and environmental provisions... (908) (473) (499) (25) 1,406 (499) Onerous property leases..... 139 -- 139 139 (278) 139 Deferred taxation........... (4,756) (1,800) (6,082) (4,513) 11,069 (6,082) Fourth quarterly dividend... -- -- 972 -- -- 972 Pension liability adjustment (50) -- (144) (144) 194 (144) Other....................... (37) -- (197) (197) 234 (197) ------- ------- ------- ------- ------- ------- Shareholders' interest as adjusted to accord with US GAAP....... 21,687 8,163 37,134 23,191 (52,337) 37,838 ======= ======= ======= ======= ======= ======= </TABLE> F - 95
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Cash flow statement <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 2000 Net cash inflow (outflow) from operating activities........ (467) 1,683 (12,830) 8,425 23,605 20,416 Dividends from joint ventures -- -- -- 645 -- 645 Dividends from associated undertakings................ -- -- -- 394 -- 394 Dividends from subsidiaries.. 899 -- 793 -- (1,692) -- Net cash inflow (outflow) from servicing of finance and returns on investments (13) (1) 431 (1,309) -- (892) Tax paid .................... (470) (754) 5 (4,979) -- (6,198) Net cash inflow (outflow) for capital expenditure and financial investment (1) (552) (64) (6,455) -- (7,072) Net cash inflow for acquisitions and disposals............... 12 45 18,118 6,295 (23,605) 865 Equity dividends paid........ -- -- (4,415) (1,692) 1,692 (4,415) ------- ------- ------- ------- ------- ------- Net cash inflow (outflow).... (40) 421 2,038 1,324 -- 3,743 ======= ======= ======= ======= ======= ======= Financing.................... (41) 435 2,039 980 -- 3,413 Management of liquid resources -- -- -- 452 -- 452 Increase (decrease) in cash.. 1 (14) (1) (108) -- (122) ------- ------- ------- ------- ------- ------- (40) 421 2,038 1,324 -- 3,743 ======= ======= ======= ======= ======= ======= </TABLE> The consolidated statement of cash flows presented in accordance with SFAS 95 is as follows <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> Net cash provided by operating activities........ (51) 928 (11,601) 3,272 22,056 14,604 Net cash used in investing activities 11 (507) 18,054 (160) (23,724) (6,326) Net cash used in financing activities 41 (435) (6,454) (2,672) 1,668 (7,852) Currency translation differences relating to cash and cash equivalents. -- -- -- (50) -- (50) ------- ------- ------- ------- ------- ------- Cash and cash equivalents at beginning of year........ (3) (18) 3 1,473 -- 1,455 ------- ------- ------- ------- ------- ------- Cash and cash equivalents at end of year.............. (2) (32) 2 1,863 -- 1,831 ======= ======= ======= ======= ======= ======= </TABLE> F - 96
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Cash flow statement <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 1999 Net cash inflow from operating activities........ 23 739 282 10,455 (1,209) 10,290 Dividends from joint ventures -- -- -- 949 -- 949 Dividends from associated undertakings................ -- -- -- 219 -- 219 Dividends from subsidiaries.. -- -- 4,577 -- (4,577) -- Net cash inflow (outflow) from servicing of finance and returns on investments (4) -- 438 (1,437) -- (1,003) Tax paid .................... (66) (62) (119) (1,013) -- (1,260) Net cash outflow for capital expenditure and financial investment.... -- (393) (77) (4,915) -- (5,385) Net cash inflow (outflow) for acquisitions and disposals............... 11 1 (1,209) 231 1,209 243 Equity dividends paid........ -- -- (4,135) (4,577) 4,577 (4,135) ------- ------- ------- ------- ------- ------- Net cash inflow (outflow).... (36) 285 (243) (88) -- (82) ======= ======= ======= ======= ======= ======= Financing.................... (35) 273 (245) (947) -- (954) Management of liquid resources -- -- -- (93) -- (93) Increase in cash............. (1) 12 2 952 -- 965 ------- ------- ------- ------- ------- ------- (36) 285 (243) (88) -- (82) ======= ======= ======= ======= ======= ======= </TABLE> The consolidated statement of cash flows presented in accordance with SFAS 95 is as follows <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> Net cash provided by operating activities.......... (47) 677 5,178 8,947 (5,855) 8,900 Net cash used in investing activities 11 (392) (1,286) (4,684) 1,429 (4,922) Net cash used in financing activities 35 (273) (3,890) (3,630) 4,426 (3,332) Currency translation differences relating to cash and cash equivalents.. -- -- -- 15 -- 15 ------- ------- ------- ------- ------- ------- Cash and cash equivalents at beginning of year....... (2) (30) 1 825 -- 794 ------- ------- ------- ------- ------- ------- Cash and cash equivalents at end of year............. (3) (18) 3 1,473 -- 1,455 ======= ======= ======= ======= ======= ======= </TABLE> F - 97
NOTES TO FINANCIAL STATEMENTS (continued) Note 46-- Condensed consolidating information on certain US Subsidiaries (continued) Cash flow statement <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> For the year ended December 31, 1998 Net cash inflow (outflow) from operating activities........ 7 1,138 (2,038) 10,479 -- 9,586 Dividends from joint ventures -- -- -- 544 -- 544 Dividends from associated undertakings................ -- -- -- 422 -- 422 Dividends from subsidiaries.. 251 -- 2,716 -- (2,967) -- Net cash inflow (outflow) from servicing of finance and returns on investments (10) 1 459 (1,275) -- (825) Tax paid .................... (120) (378) (30) (1,177) -- (1,705) Net cash outflow for capital expenditure and financial investment.... (5) (732) (254) (6,307) -- (7,298) Net cash inflow for acquisitions and disposals............... 19 4 -- 755 -- 778 Equity dividends paid........ (100) (749) (1,015) (3,511) 2,967 (2,408) ------- ------- ------- ------- ------- ------- Net cash outflow............. 42 (716) (162) (70) -- (906) ======= ======= ======= ======= ======= ======= Financing.................... 43 (752) (161) 493 -- (377) Management of liquid resources -- -- -- (596) -- (596) Increase in cash............. (1) 36 (1) 33 -- 67 ------- ------- ------- ------- ------- ------- 42 (716) (162) (70) -- (906) ======= ======= ======= ======= ======= ======= </TABLE> The consolidated statement of cash flows presented in accordance with SFAS 95 is as follows <TABLE> <CAPTION> Issuer Issuer Guarantor ------------------------------------- BP Eliminations BP America Exploration BP Amoco Other and BP Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group ---------- ------------ -------- ------------ ----------------- ------ ($ million) <S> <C> <C> <C> <C> <C> <C> Net cash provided by operating activities........ 128 761 1,107 8,993 (2,496) 8,493 Net cash used in investing activities 14 (728) (254) (5,552) (341) (6,861) Net cash used in financing activities (143) 3 (854) (4,004) 2,837 (2,161) Currency translation differences relating to cash and cash equivalents. -- -- -- (15) -- (15) ------- ------- ------- ------- ------- ------- Cash and cash equivalents at beginning of year (1) (66) 2 1,403 -- 1,338 ------- ------- ------- ------- ------- ------- Cash and cash equivalents at end of year.............. (2) (30) 1 825 -- 794 ======= ======= ======= ======= ======= ======= </TABLE> F - 98
SUPPLEMENTARY OIL AND GAS INFORMATION (Unaudited) The following tables show estimates of the Group's net proved reserves of crude oil and natural gas at December 31,2000, 1999 and 1998. Estimated net proved reserves of crude oil (a) <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- (millions of barrels) <S> <C> <C> <C> <C> <C> 2000 Subsidiary undertakings At January 1 Developed............................ 1,158 190 2,930 550 4,828 Undeveloped.......................... 183 95 932 497 1,707 -------- -------- -------- -------- -------- 1,341 285 3,862 1,047 6,535 ======== ======== ======== ======== ======== Changes in year attributable to: Revisions of previous estimates...... 17 50 40 5 112 Purchases of reserves-in-place....... 146 -- 554 441 1,141 Extensions, discoveries and other additions.................... 1 -- 255 201 457 Improved recovery.................... 131 71 105 22 329 Production........................... (195) (33) (251) (143) (622) Sales of reserves-in-place........... (49) -- (1,372) (23) (1,444) -------- -------- -------- -------- -------- 51 88 (669) 503 (27) ======== ======== ======== ======== ======== At December 31 Developed............................ 1,138 213 2,150 817 4,318 Undeveloped.......................... 254 160 1,043 733 2,190 -------- -------- -------- -------- -------- 1,392 373 3,193 1,550 6,508 ======== ======== ======== ======== ======== Associated undertakings BP share At January 1.................................................................. 1,037 Net revisions and other additions........................................... 93 Purchases of reserves-in-place.............................................. 73 Production.................................................................. (68) ------ At December 31................................................................ 1,135 ====== Total Group and BP share of associated undertakings.......................... 7,643 ====== </TABLE> F - 99
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Estimated net proved reserves of crude oil (a) (continued) <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- (millions of barrels) <S> <C> <C> <C> <C> <C> 1999 Subsidiary undertakings At January 1 Developed............................ 1,258 220 2,982 858 5,318 Undeveloped.......................... 270 51 979 686 1,986 -------- -------- -------- -------- -------- 1,528 271 3,961 1,544 7,304 ======== ======== ======== ======== ======== Changes in year attributable to: Revisions of previous estimates...... (10) 12 11 1 14 Purchases of reserves-in-place....... 6 -- 4 -- 10 Extensions, discoveries and other additions.................... 1 24 100 44 169 Improved recovery.................... 28 14 87 83 212 Production........................... (212) (36) (275) (149) (672) Sales of reserves-in-place........... -- -- (33) (476) (509) Transfers from associated undertakings -- -- 7(d) -- 7 -------- -------- -------- -------- -------- (187) 14 (99) (497) (769) ======== ======== ======== ======== ======== At December 31 Developed............................ 1,158 190 2,930 550 4,828 Undeveloped.......................... 183 95 932 497 1,707 -------- -------- -------- -------- -------- 1,341 285 3,862(b)(c) 1,047 6,535 ======== ======== ======== ======== ======== Associated undertakings BP share At January 1.................................................................. 1,128 Net revisions and other additions........................................... (21) Purchases of reserves-in-place.............................................. -- Production.................................................................. (63) Transfers to subsidiary undertakings........................................ (7)(d) ------ At December 31................................................................ 1,037 ====== Total Group and BP share of associated undertakings.......................... 7,572 ====== </TABLE> F - 100
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Estimated net proved reserves of crude oil (a) (concluded) <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- (millions of barrels) <S> <C> <C> <C> <C> <C> 1998 Subsidiary undertakings At January 1 Developed............................ 779 241 3,039 916 4,975 Undeveloped.......................... 744 46 1,210 637 2,637 -------- -------- -------- -------- -------- 1,523 287 4,249 1,553 7,612 ======== ======== ======== ======== ======== Changes in year attributable to: Revisions of previous estimates...... 106 17 (90) (76) (43) Purchases of reserves-in-place....... 3 -- 10 1 14 Extensions, discoveries and other additions.................... 38 4 57 222 321 Improved recovery.................... 80 1 69 32 182 Production........................... (189) (38) (283) (141) (651) Sales of reserves-in-place........... (33) -- (51) (47) (131) -------- -------- -------- -------- -------- 5 (16) (288) (9) (308) ======== ======== ======== ======== ======== At December 31 Developed............................ 1,258 220 2,982 858 5,318 Undeveloped.......................... 270 51 979 686 1,986 -------- -------- -------- -------- -------- 1,528 271 3,961(b)(c) 1,544 7,304 ======== ======== ======== ======== ======== Associated undertakings BP share At January 1.................................................................. 1,110 Purchases of reserves-in-place.............................................. 90 Production.................................................................. (72) ------ At December 31................................................................ 1,128 ====== Total Group and BP share of associated undertakings.......................... 8,432 ====== </TABLE> - ---------- (a) Crude oil includes natural gas liquids and condensate. Net proved reserves of crude oil exclude production royalties due to others. (b) Proved reserves in the Prudhoe Bay field in Alaska include an estimated 91 million barrels (94 million barrels at December 31, 1999 and nil at December 31, 1998) upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. (c) The Group's common interest in Altura Energy was sold in 2000. The minority interest in Altura Energy included 309 million barrels at December 31, 1999 and 280 million barrels at December 31, 1998. Associated undertakings (d) Transfer from associated to subsidiary undertakings comprise reserves in Crescendo Resources after the acquisition of the majority interest from Repsol-YPF. F - 101
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Estimated net proved reserves of natural gas (a) <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- (billions of cubic feet) <S> <C> <C> <C> <C> <C> 2000 At January 1 Developed............................ 3,354 282 10,439 6,423 20,498 Undeveloped.......................... 919 63 1,552 10,770 13,304 -------- -------- -------- -------- -------- 4,273 345 11,991 17,193 33,802 ======== ======== ======== ======== ======== Changes in year attributable to: Revisions of previous estimates...... (17) 23 150 331 487 Purchases of reserves-in-place....... 1,099 -- 3,034 2,313 6,446 Extensions, discoveries and other additions................ 253 -- 923 2,343 3,519 Improved recovery.................... 29 28 980 91 1,128 Production........................... (605) (50) (1,174)(b) (916) (2,745) Sales of reserves-in-place........... (76) -- (1,393) (68) (1,537) -------- -------- -------- -------- -------- 683 1 2,520 4,094 7,298 ======== ======== ======== ======== ======== At December 31 Developed............................ 3,898 275 12,111 7,985 24,269 Undeveloped.......................... 1,058 71 2,400 13,302 16,831 -------- -------- -------- -------- -------- 4,956 346 14,511 21,287 41,100 ======== ======== ======== ======== ======== Associated undertakings BP share At January 1.................................................................. 1,724 Net revisions and other changes............................................. 427 Purchases of reserves-in-place.............................................. 763 Production.................................................................. (96) ------ At December 31................................................................ 2,818 ====== Total Group and BP share of associated undertakings.......................... 43,918 ====== </TABLE> F - 102
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Estimated net proved reserves of natural gas (a) (continued) <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- (billions of cubic feet) <S> <C> <C> <C> <C> <C> 1999 At January 1 Developed............................ 3,536 324 9,637 6,054 19,551 Undeveloped.......................... 1,107 38 1,658 8,647 11,450 -------- -------- -------- -------- -------- 4,643 362 11,295 14,701 31,001 ======== ======== ======== ======== ======== Changes in year attributable to: Revisions of previous estimates...... 1 9 215 (107) 118 Purchases of reserves-in-place....... 3 -- -- 12 15 Extensions, discoveries and other additions................ 79 34 417 3,296 3,826 Improved recovery.................... 22 -- 242 299 563 Production........................... (475) (60) (907)(b) (752) (2,194) Sales of reserves-in-place........... -- -- (143) (256) (399) Tranfers from associated undertakings -- -- 872(d) -- 872 -------- -------- -------- -------- -------- (370) (17) 696 2,492 2,801 ======== ======== ======== ======== ======== At December 31 Developed............................ 3,354 282 10,439 6,423 20,498 Undeveloped.......................... 919 63 1,552 10,770 13,304 -------- -------- -------- -------- -------- 4,273 345 11,991(c) 17,193 33,802 ======== ======== ======== ======== ======== Associated undertakings BP share At January 1.................................................................. 1,766 Net revisions and other changes............................................. 549 Purchases of reserves-in-place.............................................. 378 Production.................................................................. (97) Transfers to subsidiary undertakings........................................ (872)(d) ------ At December 31................................................................ 1,724 ====== Total Group and BP share of associated undertakings.......................... 35,526 ====== </TABLE> F - 103
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Estimated net proved reserves of natural gas (a) (concluded) <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- (billions of cubic feet) <S> <C> <C> <C> <C> <C> 1998 At January 1 Developed............................ 3,161 372 10,284 5,612 19,429 Undeveloped.......................... 1,868 50 1,819 7,208 10,945 -------- -------- -------- -------- -------- 5,029 422 12,103 12,820 30,374 ======== ======== ======== ======== ======== Changes in year attributable to: Revisions of previous estimates...... (16) -- 161 (148) (3) Purchases of reserves-in-place....... -- -- 104 37 141 Extensions, discoveries and other additions.................... 129 11 176 4,439 4,755 Improved recovery.................... 25 -- 277 47 349 Production........................... (460) (71) (897)(b) (665) (2,093) Sales of reserves-in-place........... (64) -- (629) (1,829) (2,522) -------- -------- -------- -------- -------- (386) (60) (808) 1,881 627 ======== ======== ======== ======== ======== At December 31 Developed............................ 3,536 324 9,637 6,054 19,551 Undeveloped.......................... 1,107 38 1,658 8,647 11,450 -------- -------- -------- -------- -------- 4,643 362 11,295(c) 14,701 31,001 ======== ======== ======== ======== ======== Associated undertakings BP share At January 1.................................................................. 1,748 Net revisions and other changes............................................. 47 Purchases of reserves-in-place.............................................. 52 Production.................................................................. (81) ------ At December 31................................................................ 1,766 ====== Total Group and BP share of associated undertakings.......................... 32,767 ====== </TABLE> - ---------- (a) Net proved reserves of natural gas exclude production royalties due to others. (b) Includes 55 billion cubic feet of natural gas consumed in Alaskan operations (1999, 77 billion cubic feet and 1998, 79 billion cubic feet). (c) The Group's common interest in Altura Energy was sold in 2000. The minority interest in Altura Energy included 155 billion cubic feet of natural gas at December 31, 1999 and 117 billion cubic feet at December 31, 1998. Associated Undertakings (d) Transfers from associated to subsidiary undertakings comprise reserves in Crescendo Resources after the acquisition of the majority interest from Repsol-YPF. F - 104
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves The following tables set out the standardized measures of discounted future net cash flows, and changes therein, relating to crude oil and natural gas production from the Group's estimated proved reserves. This information is prepared in compliance with the requirements of FASB Statement of Financial Accounting Standards No. 69 -- 'Disclosures about Oil and Gas Producing Activities'. Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of future production, the estimation of crude oil and natural gas reserves and the application of year end crude oil and natural gas prices and exchange rates. Furthermore, both reserve estimates and production forecasts are subject to revision as further technical information becomes available and economic conditions change. BP cautions against relying on the information presented because of the highly arbitrary nature of assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements. <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> At December 31, 2000 Future cash inflows (a)................ 43,800 9,400 187,200 94,100 334,500 Future production and development costs (b) 19,000 2,800 38,400 27,300 87,500 Future taxation (c).................... 7,100 4,700 45,600 27,100 84,500 -------- -------- -------- -------- -------- Future net cash flows.................. 17,700 1,900 103,200 39,700 162,500 10% annual discount (d)................ 5,000 700 49,200 18,000 72,900 -------- -------- -------- -------- -------- Standardized measure of discounted future net cash flows....................... 12,700 1,200 54,000 21,700 89,600 ======== ======== ======== ======== ======== At December 31, 1999 Future cash inflows (a)................ 42,400 7,900 101,500 49,500 201,300 Future production and development costs (b) 18,800 2,000 32,500 13,700 67,000 Future taxation (c).................... 5,900 4,200 23,300 15,800 49,200 -------- -------- -------- -------- -------- Future net cash flows.................. 17,700 1,700 45,700 20,000 85,100 10% annual discount (d)................ 4,700 400 23,200 8,400 36,700 -------- -------- -------- -------- -------- Standardized measure of discounted future net cash flows....................... 13,000 1,300 22,500 11,600 48,400 ======== ======== ======== ======== ======== At December 31, 1998 Future cash inflows (a)................ 27,100 3,700 44,800 36,500 112,100 Future production and development costs (b) 18,700 2,200 27,500 14,300 62,700 Future taxation (c).................... 2,000 800 3,100 9,900 15,800 -------- -------- -------- -------- -------- Future net cash flows.................. 6,400 700 14,200 12,300 33,600 10% annual discount (d)................ 1,300 100 7,000 6,600 15,000 -------- -------- -------- -------- -------- Standardized measure of discounted future net cash flows....................... 5,100 600 7,200 5,700 18,600 ======== ======== ======== ======== ======== </TABLE> F - 105
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves (concluded) The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31, 2000, 1999 and 1998: <TABLE> <CAPTION> Years ended December 31, ------------------------ 2000 1999 1998 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and transfers of oil and gas produced, net of production costs...................................... (18,400) (12,600) (6,500) Development costs incurred during the year.............. 4,500 2,900 4,700 Extensions, discoveries and improved recovery, less related costs 13,100 6,200 3,200 Net changes in prices and production costs (e).......... 51,100 47,900 (30,900) Revisions of previous reserve estimates................. 900 2,600 -- Net change in taxation.................................. (14,800) (18,000) 10,800 Future development costs................................ (2,400) (200) (1,000) Net change in purchase and sales of reserves-in-place... 2,400 (900) (200) Addition of 10% annual discount......................... 4,800 1,900 3,500 ------ ------ ------ Total change in the standardized measure during the year 41,200 29,800 (16,400) ====== ====== ====== </TABLE> - ---------- (a) Future cash inflows are computed by applying year-end oil and natural gas prices and exchange rates to future annual production levels estimated by the Group's petroleum engineers. (b) Production costs (which include petroleum revenue tax in the UK) and development costs relating to future production of proved reserves are based on year-end cost levels and assume continuation of existing economic conditions. Future decommissioning costs are included. (c) Taxation is computed using appropriate year-end income tax rates. (d) Future net cash flows from oil and natural gas production are discounted at 10% regardless of the Group assessment of the risk associated with its producing activities. (e) Net changes in prices and production costs includes the effect of exchange movements. Associated undertakings In addition, at December 31, 2000 the Group's share of the standardized measure of discounted future net cash flows of associated undertakings amounted to $3,100 million ($2,420 million at December 31, 1999 and $715 million at December 31, 1998). F - 106
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Operational and statistical information The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Produced from own reserves The following table shows crude oil and natural gas production from the Group's own reserves for the years indicated: <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total(d) -------- -------- -------- -------- -------- (thousand barrels per day) <S> <C> <C> <C> <C> <C> Production for the year (a) Crude oil (b) 2000................................... 534 90 729 575 1,928 1999................................... 580 100 804 577 2,061 1998................................... 518 105 841 585 2,049 </TABLE> <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total(e) -------- -------- -------- -------- -------- (million cubic feet per day) <S> <C> <C> <C> <C> <C> Natural gas (c) 2000................................... 1,652 136 3,054 2,767 7,609 1999................................... 1,301 164 2,369 2,233 6,067 1998................................... 1,258 200 2,401 1,949 5,808 </TABLE> - ---------- (a) All volumes are net of royalty. (b) Crude oil includes natural gas liquid and condensate. (c) Natural gas production excludes gas consumed in operations. (d) Includes amounts produced for the Group by associated undertakings of 186,000 b/d in 2000 (1999, 170,000 b/d and 1998, 208,000 b/d). (e) Includes amounts produced for the Group by associated undertakings of 263 mmcf/d in 2000 (1999, 264 mmcf/d and 1998, 221 mmcf/d). F - 107
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued) (Unaudited) Operational and statistical information (continued) Productive oil and gas wells and acreage The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and natural gas acreage in which the Group and its associated undertakings had interests as of December 31, 2000. A 'gross' well or acre is one in which a whole or fractional working interest is owned, while the number of 'net' wells or acres is the sum of the whole or fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves. Number of productive oil and gas wells <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- <S> <C> <C> <C> <C> <C> At December 31, 2000 Oil wells (a) -- gross.............. 494 71 9,341 10,185 20,091 -- net................ 225.9 26.5 3,500.5 3,022.5 6,775.4 Gas wells (b) -- gross.............. 545 36 15,272 2,727 18,580 -- net................ 242.2 12.4 8,523.6 2,365.6 11,143.8 </TABLE> - ---------- (a) Includes approximately 2,400 gross (515.0 net) multiple completion wells (more than one formation producing into the same well bore). (b) Includes 1,508 gross (724.1 net) multiple completion wells. (c) If one of the multiple completions in a well is an oil completion, the well is classified as an oil well. Oil and natural gas acreage <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- <S> <C> <C> <C> <C> <C> At December 31, 2000 (thousands of acres) Developed --gross.............................. 691 128 13,039 6,296 20,154 --net................................ 338.1 43.7 6,522.5 2,168.0 9,072.3 Undeveloped (a) --gross.............................. 2,712 4,088 10,061 121,258 138,119 --net................................ 1,248.5 1,505.1 6,224.8 49,462.0 58,440.4 </TABLE> - ---------- (a) Undeveloped acreage includes leases and concessions. F - 108
SUPPLEMENTARY OIL AND GAS INFORMATION (Concluded) (Unaudited) Net oil and gas wells completed or abandoned The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the years indicated by the Group and its associated undertakings. Productive wells include wells in which hydrocarbons were encountered and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing hydrocarbons in sufficient quantities to justify completion. <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- 2000 <S> <C> <C> <C> <C> <C> Exploratory --productive......................... 2.4 0.4 21.5 19.9 44.2 --dry................................ 0.0 1.3 12.4 7.2 20.9 Development --productive......................... 12.6 2.5 398.4 425.2 838.7 --dry................................ 1.9 0.0 45.7 23.4 71.0 1999 Exploratory --productive......................... 0.5 0.5 3.7 10.1 14.8 --dry................................ 1.1 0.9 1.4 6.6 10.0 Development --productive......................... 27.3 1.3 274.4 160.6 463.6 --dry................................ 1.7 0.3 10.5 15.4 27.9 1998 Exploratory --productive......................... 2.3 3.6 18.9 32.1 56.9 --dry................................ 2.1 2.1 12.1 22.4 38.7 Development --productive......................... 32.2 1.4 424.4 261.5 719.5 --dry................................ 1.1 -- 16.7 30.6 48.4 </TABLE> Drilling and production activities in progress The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the Group and its associated undertakings as of December 31, 2000. Suspended development wells and long-term suspended exploratory wells are also included in the table. <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- <S> <C> <C> <C> <C> <C> At December 31, 2000 Exploratory --gross.............................. 2 1 24 29 56 --net................................ 0.7 0.2 16.6 5.7 23.2 Development --gross.............................. 14 3 99 92 208 --net................................ 5.3 1.3 56.9 26.4 89.9 </TABLE> F - 109
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS <TABLE> <CAPTION> Additions ---------------------- Charged to Charged to Balance at costs and other Transfers/ Balance January 1, expenses accounts(a) Deductions December 31, ---------- ---------- ---------- ---------- ----------- ($ million) <S> <C> <C> <C> <C> <C> 2000 Fixed assets-- Investments (b) 309 252 (6) (50) 505 ========== ========== ========== ========== ========== Doubtful debts (b)............ 117 99 117 24 357 ========== ========== ========== ========== ========== Decommissioning provisions.... 2,785 139 (23) 100(c) 3,001 ========== ========== ========== ========== ========== 1999 Fixed assets-- Investments (b) 230 83 (2) (2) 309 ========== ========== ========== ========== ========== Doubtful debts (b)............ 126 12 (13) (8) 117 ========== ========== ========== ========== ========== Decommissioning provisions.... 3,310 80 (472) (133) 2,785 ========== ========== ========== ========== ========== 1998 Fixed assets-- Investments (b) 25 200 -- 5 230 ========== ========== ========== ========== ========== Doubtful debts (b)............ 130 35 (22) (17) 126 ========== ========== ========== ========== ========== Decommissioning provisions.... 3,201 130 10 (31) 3,310 ========== ========== ========== ========== ========== </TABLE> - ---------- (a) Principally currency translations, apart from 1999 for decommissioning provisions which includes the impact of adopting FRS12. (b) Deducted in the balance sheet from the assets to which they apply. (c) Includes $484 million additional provisions in respect of acquisitions. S - 1