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, 1999 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. <TABLE> <CAPTION> <S> <C> 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 </TABLE> Securities registered or to be registered pursuant to Section 12(g) of the Act. NONE - -------------------------------------------------------------------------------- Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. NONE - -------------------------------------------------------------------------------- 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. <TABLE> <CAPTION> <S> <C> ORDINARY SHARES OF 25C EACH 19,484,024,424 CUMULATIVE FIRST PREFERENCE SHARES OF L1 EACH 7,232,838 CUMULATIVE SECOND PREFERENCE SHARES OF L1 EACH 5,473,414 </TABLE> 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 Exchange Rates................................................ 4 PART I Item 1 Description of Business....................................... 5 General.................................................. 5 Exploration and Production............................... 9 Refining and Marketing................................... 23 Chemicals................................................ 29 Other Businesses and Corporate........................... 34 Regulation of the Group's Business....................... 36 Environmental Protection................................. 38 Additional Factors Which May Affect Business............. 42 Item 2 Description of Property....................................... 43 Item 3 Legal Proceedings............................................. 44 Item 4 Control of Registrant......................................... 44 Item 5 Nature of Trading Market...................................... 45 Item 6 Exchange Controls and Other Limitations Affecting Security Holders............................................ 46 Item 7 Taxation...................................................... 46 Item 8 Selected Financial Data....................................... 50 Summarized Financial Information......................... 50 Dividends................................................ 52 Item 9 Management's Discussion and Analysis of Financial Condition and Results of Operations......................... 54 Item 9A Quantitative and Qualitative Disclosures about Market Risk.... 67 Item 10 Directors and Officers of Registrant.......................... 73 Item 11 Compensation of Directors and Officers........................ 75 Item 12 Options to Purchase Securities from Registrant or Subsidiaries................................................ 87 Item 13 Interest of Management in Certain Transactions................ 87 PART III Item 15 Defaults upon Senior Securities............................... 88 Item 16 Changes in Securities, Changes in Security for Registered Securities and Use of Proceeds................... 88 PART IV Item 18 Financial Statements.......................................... 89 Item 19 Financial Statements and Exhibits............................. 89 </TABLE> - ---------- Note: Omitted items are inapplicable. 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. 'Associated undertaking' -- An undertaking in which the BP Amoco Group has a participating interest and over whose operating and financial policy the BP Amoco 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' or 'BP Group'-- The British Petroleum Company p.l.c. and its subsidiaries. 'BP p.l.c.'-- The British Petroleum Company p.l.c. 'BP Amoco', 'BP Amoco Group' or the 'Group' -- The Company 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. '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 'L' -- The pound sterling. 'Preference Shares'-- Cumulative First Preference Shares and Cumulative Second Preference Shares in BP Amoco p.l.c. of L1 each. 'Subsidiary undertaking' -- An undertaking in which the BP Amoco 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. 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 L1. <TABLE> <CAPTION> Calendar year at Year End Average(a) High Low - ----------- ----------- ------- ---- ---- <S> <C> <C> <C> <C> 1995............................................ 1.55 1.58 1.64 1.53 1996............................................ 1.71 1.57 1.71 1.49 1997............................................ 1.64 1.64 1.70 1.58 1998............................................ 1.66 1.66 1.72 1.61 1999 ........................................... 1.62 1.62 1.66 1.60 2000 (through March 24) (b)..................... -- -- 1.65 1.57 </TABLE> - ---------- (a) The average of the Noon Buying Rates on the last day of each month during the calendar year. (b) The Noon Buying Rate on March 24, 2000 was $1.59 = L1. 4
PART I ITEM 1 -- DESCRIPTION OF BUSINESS 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 AMOCO BUSINESSES BP Amoco 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 BP 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. BP Amoco 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 main businesses are Exploration and Production, 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, natural gas processing and gas and power marketing (midstream activities). 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 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 Amoco has a strong portfolio of assets in its three 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 exploration or production operations in several other areas including Latin America, the Caspian Sea region and Africa. -- In Refining and Marketing we have a strong presence in the Midwest, East and Southeast of the USA through our Amoco brand and this is reinforced in the Midwest and Southeast by our BP brand. In Europe we have a strong retail position in fuels through a joint venture with ExxonMobil Corporation (ExxonMobil). We have agreed to purchase ExxonMobil's share of this joint venture. In addition we have established or growing retail 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 plants. 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). The integration of BP and Amoco following the merger was completed in 1999 and the anticipated cost savings at a rate of $2 billion per annum before tax were achieved by the end of that year. Following completion of the merger on December 31, 1998 and in the context of low oil prices at the time, BP Amoco 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 prices. 5
Our new strategy has evolved from those of BP and Amoco. 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. We are developing a new business division - Gas and Power - 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. In July 1999, we announced a new set of targets taking us through to the end of 2001. Our aim is to improve returns by around five to six percentage points, compared with the base-line of 1998, on the basis of cautious assumptions about the trading environment. We cannot, and do not, rely on oil prices maintaining their current levels. Even allowing for price fluctuation, we believe we can continue to improve performance through selective upgrading of the portfolio, including sustained reductions in costs, a steady programme of investment in the existing business amounting to some $24-26 billion over three years and a programme to divest some $10 billion of assets by the end of 2001. Our financial framework is to maintain a ratio of net debt to net debt plus equity within a range of around 25-30% and a dividend policy which aims to return to shareholders around 50% of estimated average replacement cost profit before exceptional items through the business cycle. If circumstances give us a larger surplus it is anticipated that cash will either be used to fund further growth investment or be returned to shareholders. The following table summarizes the Group's turnover, results and capital expenditure for the last five years and total assets at the end of each of those years. <TABLE> <CAPTION> Years ended December 31, (a) ----------------------------------------------- 1999 1998 1997 1996 1995 ----- ----- ----- ----- ----- ($ million) <S> <C> <C> <C> <C> <C> Turnover............................ 101,180 83,732 108,564 102,064 84,216 Less: joint ventures................ 17,614 15,428 16,804 -- -- ------- ------- ------- ------- ------- Group Turnover (sales to third parties) 83,566 68,304 91,760 102,064 84,216 Total replacement cost operating profit 8,894 6,521 10,683 10,634 8,264 Profit for the year*................ 5,008 3,220 5,673 7,417 3,700 Capital expenditure and acquisitions 7,345 10,362 11,420 10,288 8,380 Total assets........................ 89,561 84,915 86,279 88,651 81,499 </TABLE> - -------- * After minority shareholders' interest (a) As restated for the effect of the adoption of Financial Reporting Standard No.12 `Provisions, Contingent Liabilities and Contingent Assets'. For further information see Note 43 of Notes to Financial Statements. Information for 1999, 1998 and 1997 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 -- Note 45 of Notes to Financial Statements. 6
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, ----------------------------------------------- 1999 1998 1997 1996 1995 ----- ----- ----- ----- ----- <S> <C> <C> <C> <C> <C> Total crude oil production (thousand barrels per day)(a).......... 2,061 2,049 1,930 1,903 1,873 Total natural gas production (million cubic feet per day)(a)........ 6,067 5,808 5,858 5,917 5,485 Total estimated net proved crude oil reserves (million barrels)(b)...... 6,535 7,304 7,612 7,325 6,987 Total estimated net proved natural gas... reserves (billion cubic feet) (b)....... 33,802 31,001 30,374 30,349 29,534 </TABLE> - ---------- (a) Includes BP Amoco'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 1999, 1,172 million barrels of oil and natural gas, on an oil equivalent* basis (mmboe), were added to BP Amoco's proved reserves, more than replacing the volume produced. In addition, 157 mmboe were transferred from reserves of equity-accounted entities into net proved reserves of the BP Amoco Group after the dissolution of Crescendo Resources when BP Amoco purchased a majority of Repsol YPF's interest. After allowing for production which amounted to 1,050 mmboe and sales net of purchases totalling 565 mmboe, BP Amoco's proved reserves decreased to 12,363 mmboe. These proved reserves are mainly located in the USA (48%), the UK (17%) and Trinidad and Tobago (17%). RECENT DEVELOPMENTS THE PROPOSED COMBINATION OF BP AMOCO AND ARCO On April 1, 1999 the Board of BP Amoco announced that it had reached agreement on a proposed combination (the combination) with the Atlantic Richfield Company (ARCO) of Los Angeles. The agreement relating to the proposed combination (the Combination Agreement), approved by the boards of both BP Amoco and ARCO, provides that all common shareholders of ARCO, with the exception of BP Amoco, ARCO or any of their subsidiaries, will receive 9.84 BP Amoco ordinary shares of US$0.25 each in the form of BP Amoco ADSs or, at the election of the shareholder, BP Amoco ordinary shares, in return for the cancellation of each of their shares (other than the shares held by CH-Twenty Holdings, LLC, a subsidiary of ARCO) (the Cancelled ARCO Shares). It also provides for the issue to BP Amoco of new common shares equal in number to the Cancelled ARCO Shares by a newly enlarged ARCO formed by a statutory merger of Prairie Holdings, Inc. (a direct wholly owned subsidiary of BP Amoco) into and with ARCO. Any right to a fraction of a BP Amoco ADS or an odd lot of less than six BP Amoco ordinary shares will be satisfied by a cash payment. Both ARCO and BP Amoco shareholders voted overwhelmingly in favour of the combination at shareholders' meetings on August 30, 1999 and September 1, 1999, respectively. BP Amoco and ARCO announced in early November 1999 that they had reached provisional agreement with the Alaskan State Governor on a package of asset disposals and other measures designed to secure Alaskan government acceptance for the proposed combination of the two companies. Subject to the completion of the combination, BP Amoco would sell 175,000 barrels of production per day together with associated infrastructure, 620,000 acres of state and federal exploration leases, and matching stakes in the Trans Alaska Pipeline System (TAPS). The provisional agreement was finalized into an agreement with the State of Alaska (the Alaskan Charter Agreement) made in early December 1999. On February 4, 2000 the US Federal Trade Commission (FTC) filed a complaint in the US District Court (the Court) seeking a preliminary injunction to prevent closing of the combination. The Attorney Generals for the States of California, Oregon and Washington (the Western States) also filed complaints with the same Court. The Attorney General for the State of Alaska joined in the Court proceedings in support of the combination. - ---------- * Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels. 7
On March 15, 2000 BP Amoco announced that it and ARCO had agreed to sell ARCO's Alaskan business to Phillips Petroleum Co. (Phillips) for around $7 billion. The sale, which is subject to completion of the combination, is intended to address anti-trust concerns of the FTC. The sale to Phillips of all ARCO's Alaskan business includes a 21.9% interest in the Prudhoe Bay oil rim and 42.6% of the natural gas cap, a 55% interest in the greater Kuparuk area and a 78% interest in the Alpine field. Also included are 1.1 million net exploration acres, a 22.3% interest in the TAPS, and ARCO's crude oil shipping fleet which includes six tankers in service and three under construction. The reserves being sold total 1.9 billion barrels of oil equivalent. The Alaskan government has accepted that the sale to Phillips of all ARCO's Alaskan business satisfies the sale obligations of BP Amoco under the Alaskan Charter Agreement. Also on March 15, 2000 it was announced that the FTC, the Western States, the State of Alaska, ARCO and BP Amoco had agreed to suspend the Court proceedings, pending discussions for a consent order. On March 16, 2000 BP Amoco announced that it was at an advanced stage in discussions with the FTC on the combination and was hopeful of obtaining a consent order within a few weeks allowing the Company to close the combination. In addition, BP Amoco announced that, subject to completion of the combination, it had advised the board of Vastar Resources Inc. of the intention to make a tender offer for the minority stockholding of the company at $71 per share. ARCO already owns some 82 percent of Vastar. On March 23, 2000 BP Amoco and ARCO jointly agreed to extend the termination date of the Combination Agreement from March 31, 2000 to June 30, 2000. On March 24, 2000 ExxonMobil Corporation (ExxonMobil) filed a Complaint in State Court, Los Angeles, seeking a preliminary injunction and other relief against BP Amoco, ARCO and Phillips to prevent the sale of ARCO's Alaskan business to Phillips referred to in this section above. Completion of the combination remains subject to regulatory approvals and the satisfaction of other conditions. ANNOUNCEMENT OF INTENDED CASH OFFER TO BUY BURMAH CASTROL PLC On March 14, 2000 BP Amoco announced that it had agreed on the terms of a recommended cash offer to buy Burmah Castrol plc (Burmah Castrol) of the UK for approximately $4.7 billion (L3 billion). The recommended cash offer of L16.75 for each Burmah Castrol share had been agreed by the boards of both companies. The offer is pre-conditional and it is intended that the formal offer document will be sent to Burmah Castrol's shareholders once the pre-conditions (regulatory clearances) have been satisfied or waived. The offer will be subject to terms to be set out in the formal Offer Document and such further terms as required to comply with the rules of the London Stock Exchange and the City Code. BP AMOCO AND PETROCHINA JOINT VENTURE On March 23, 2000 BP Amoco announced that it planned to form a natural gas marketing joint venture with PetroChina aimed at supplying the energy markets of eastern China. The project is part of a strategic alliance agreed in principle between BP Amoco and PetroChina which also includes a preliminary agreement to build a fuels marketing business in China's coastal provinces with the prospect of further expansion into other regions. These agreements are subject to the execution of definitive agreements between the parties, and to all relevant government authorizations and approvals. BP Amoco also announced that it intended to acquire approximately 20% of the shares currently being offered, up to a maximum purchase price of $1 billion, by PetroChina as part of its Initial Public Offering. PetroChina is based in Beijing, China and is engaged in a broad range of petroleum-related activities; it is one of the largest companies in China in terms of sales. 8
EXPLORATION AND PRODUCTION The activities of our Exploration and Production business include oil and natural gas exploration and field development and production -- the upstream activities -- as well as the management of crude oil and natural gas pipeline assets and the processing and marketing of natural gas and power -- midstream activities. We have Exploration and Production interests in 27 countries, with the main concentration in the USA and in the UK sector of the North Sea. Production during 1999 came from 18 countries. Our most significant midstream activities are the Trans Alaska Pipeline System (BP Amoco 50%), the Forties Pipeline System (BP Amoco 100%) and the Central Area Transmission System pipeline (BP Amoco 29.5%) in the UK sector of the North Sea, and the Atlantic LNG plant (BP Amoco 34%) in Trinidad. <TABLE> <CAPTION> Years ended December 31, -------------------------- 1999 1998 1997 ----- ----- ----- ($ million) <S> <C> <C> <C> Turnover (a)............................................. 21,649 17,276 23,171 Total replacement cost operating profit.................. 7,194 3,231 7,385 Total assets............................................. 46,649 47,808 46,024 Capital expenditure and acquisitions..................... 4,212 6,318 7,879 ($ per barrel) Average BP Amoco oil realizations........................ 16.7 12.1 18.3 ($ per thousand cubic feet) Average BP Amoco US natural gas realizations............. 2.1 1.8 2.2 </TABLE> - ---------- (a) Excludes BP Amoco's share of joint venture turnover of $497 million in 1999, $348 million in 1998, and $112 million in 1997. Our Exploration and Production strategy has two key elements. The first is to maximize the value realized from our existing assets and resource base. This includes the following actions: -- 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, as well as safety and environmental performance. -- We seek opportunities for profitable growth in both the upstream and midstream activities, within the context of the market environment and Group financial policies. This includes the use of decline management and enhanced recovery technologies to increase recoveries and temper the volume decline 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 marketing expertise to secure additional revenue by transporting and processing volumes owned by other companies. -- We continually upgrade the quality of our asset portfolio by focusing investments in core areas and disposing of non-strategic assets. This can be achieved through asset swaps, purchases and sales. Examples of portfolio upgrading in 1999 include our $1 billion sale of non-core Canadian oil properties in October, the sale of our Venezuelan assets announced in November and our $400 million purchase of a majority of Repsol YPF's interest in our US-based Crescendo joint venture. In March 2000, we announced the divestment of Altura Energy Ltd (Altura), our US-based joint venture with Shell, for a total price of approximately $3.6 billion (BP Amoco 64%). The transaction is expected to close during the second quarter of 2000 and it is estimated that profit after tax of approximately $260 million will be recognized by BP Amoco in 2000. 9
The second element of our Exploration and Production strategy is to renew the business and to provide growth for the future. We do this through exploration and selected business development activity, as described below: -- Our exploration programme focuses on areas which have been relatively unexplored for political or technical reasons, and where we believe substantial volumes of low cost, high value reserves remain to be found. Principal areas of activity include Angola, Australia, Azerbaijan, Brazil, Egypt, Trinidad and Tobago and the USA. Our Crazy Horse discovery in the Gulf of Mexico, USA, is one example of this exploration growth strategy. Finding this field involved drilling through 6,000 feet of water and more than 2,000 feet of salt to a record depth of 25,770 feet. -- Our business development activities focus on obtaining an interest in areas new to BP Amoco, and extending our interests into existing core areas. Our In Salah development is a new venture (BP Amoco 65%) in which BP Amoco and the Algerian state company, Sonatrach, intend to go ahead with a $2.5-billion development of natural gas fields in the Sahara Desert. This development is expected to supply the fast growing markets of southern Europe with some 320 billion cubic feet (bcf) annually. First deliveries are expected to start in 2003. -- In a longstanding core area, the negotiation of new concession terms with the government of Egypt will enable continued investment of $450 million in our Gulf of Suez concessions. The new terms will result in the development of 160 million barrels of oil equivalent. Redevelopment activity conducted in our portfolio of giant fields should be a significant source of future growth. Following the merger 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 two successful companies to optimize further our operations and investment programme. The merger has also provided a better geographic, oil/natural gas and upstream/midstream balance in our portfolio. With cost reductions achieved in 1999, we are well on our way toward meeting our cost reduction target of $2.2 billion by 2001. BP Amoco retains its 10% equity interest (20% voting interest) in the Russian integrated oil company A O Sidanco (Sidanco). Sidanco went into bankruptcy for most of 1999 and temporarily lost ownership of a major subsidiary as a result of a forced bankruptcy sale. As part of a broad-ranging agreement between the parties involved, this subsidiary will be returned to Sidanco's ownership in 2000 and arrangements were put in place which made it possible to take Sidanco out of bankruptcy in January 2000. 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 Amoco acts as operator for many of these ventures. The Group's worldwide capital expenditure on exploration and appraisal in 1999 was $604 million, a decrease of $371 million or 38% compared with 1998, as we focused on high-graded opportunities following the merger of the BP and Amoco exploration portfolios. In 1999, we participated in 84 gross (24.9 net) exploration and appraisal wells in 17 countries. The principal areas of activity were Angola, Australia, Azerbaijan, Brazil, Egypt, and the USA. In 1999, BP Amoco obtained upstream rights in several new tracts, which are expected to provide a foundation for continued exploration success. These include the following: -- In Angola, we acquired operatorship and a 26.67% interest in a production sharing agreement covering deepwater Block 31. This new block is adjacent and geologically similar to other acreage where BP Amoco and partners have discovered several large fields. -- In Australia we won our three preferred blocks (BP Amoco 16.7% to 20% and operator) in the Canning deepwater Gazettal round. Additionally we farmed into the WA-267-P licence (BP Amoco 12.5%). -- In Brazil we were awarded two offshore blocks in the deepwater Foz do Amazonas basin offshore Northern Brazil. BP Amoco is operator of both blocks with a 30% interest in the 15,000 square kilometre block BMFZA-1, and 35% in the 25,000 square kilometre block BFZ-2. 10
-- In Egypt we obtained operating rights and 50% ownership interest in the 15,400 square kilometre West Mediterranean deepwater block. -- In the USA, in Alaska, BP Amoco and partners won 25 blocks in the National Petroleum Reserve-Alaska (NPR-A) at Lease Sale 991. A subsequent equity cross assignment with partners Chevron and Phillips resulted in BP Amoco holding 50% interest and operating rights in a total of 33 NPR-A blocks. In addition, during 1999 we relinquished exploration interests in several countries as we continued a process of focusing and shaping our portfolio. The most significant of these was the exit from offshore Nigeria, but we also relinquished the Zambezi block, offshore Mozambique, our properties offshore southern Turkey, acreage in the Latvian Baltic Sea and our interests onshore north Somalia. In 1999, we announced significant discoveries in Angola, Australia, Azerbaijan 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 Angola, we were involved in eight discoveries. Plutonio and Platina in Block 18 (BP Amoco 50% and operator), Orquidea, Cravoa, Camelia and Tulipa in Block 17 (BP Amoco 16.7%), and Chocalho and Xikomba in Block 15 (BP Amoco 26.7%). -- In Australia, we participated in the significant Geryon and Orthrus natural gas discoveries (licence WA-267-P, BP Amoco 12.5%) which lie approximately 200 kilometres west of our LNG facilities. A further four wells remain to be drilled over the next two years. -- In Azerbaijan we announced a significant gas condensate discovery, Shah Deniz (BP Amoco 25.5% and operator). Gas from this discovery should provide the basis to initiate gas exports from Azerbaijan to Turkey. -- In the deepwater US Gulf of Mexico, we announced four discoveries, Crazy Horse (BP Amoco 75% and operator), Mad Dog (BP Amoco 63% and operator), Holstein (BP Amoco 50% and operator) and Atlantis (BP Amoco 56% and operator). The Crazy Horse discovery is estimated to be the largest discovery made to date in the deepwater Gulf of Mexico. In 1999, total additions to the Group's proved reserves (excluding purchases and sales) amounted to 1,172 million barrels of oil equivalent (mmboe): 829 mmboe through extensions to existing fields and discoveries of new fields, and the remaining 343 mmboe through revisions to previous estimates and the application of improved recovery techniques. The principal reserve additions were in Egypt, Trinidad and US Gulf of Mexico as follows: -- In Egypt we added 90 million barrels (mmb) of oil reserves following the successful amendment to the concession terms for our Gulf of Suez producing properties. In addition we added 250 bcf of natural gas reserves from our Nile Delta gas discoveries following completion of gas sales agreements. -- In Trinidad and Tobago, we added through discoveries and extensions, 2.9 trillion cubic feet of natural gas, principally from the Sparrow field (BP Amoco 100% and operator). -- In the deepwater Gulf of Mexico we added 150 mmboe as we approved development of a number of fields including Crosby, King and Mica. 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, 1999, 1998, and 1997 and production for each of the three years then ended are set out in the Supplementary Oil and Gas Information in Item 19 -- Financial Statements and Exhibits. On an oil equivalent basis, natural gas represents some 47% of the Group's hydrocarbon reserves (excluding equity-accounted entities). 11
Our total hydrocarbon production (including equity-accounted entities) during 1999 averaged 3,107,000 barrels of oil equivalent per day (boe/d), an increase of 57,000 boe/d, or 1.9% compared with 1998 as production declines in mature fields were more than offset by production start-ups and build-ups to full production. About 38% of our production was in the USA and 26% in the UK. The following tables show BP Amoco's production by major field (asterisks denote fields operated by BP Amoco) for the three years 1997 to 1999, and BP Amoco's aggregate estimated net proved reserves as at December 31, 1999: CRUDE OIL (a) PRODUCTION <TABLE> <CAPTION> Net production -------------------- Field or Area Interest 1999 1998 1997 ------------- -------- ----- ----- ----- (%) (thousand barrels per day) <S> <C> <C> <C> <C> <C> Alaska (b) Prudhoe Bay* 51.2/13.8(c) 202 232 266 Kuparuk 39.2 90 92 90 Milne Point* 91.2 42 43 40 Point McIntyre 32.2 25 36 44 Endicott* 67.9 25 30 36 Other Various 21 21 22 ------ ------ ------ Total Alaska 405 454 498 Lower 48 onshore Altura Various 127 122 146 Other Various 133 140 139 ------ ------ ------ Total Lower 48 onshore 260 262 285 Gulf of Mexico (b) Mars 28.5 36 29 22 Troika 33.3 30 15 1 Pompano* 75.0 29 34 29 Other Various 44 39 33 ------ ------ ------ Total Gulf of Mexico 139 117 85 ------ ------ ------ TOTAL USA 804 833 868 ------ ------ ------ UK offshore (b) ETAP Various 80 30 -- Forties* 95.4 66 76 75 Harding* 70.0 58 60 50 Foinaven* 72.0 56 51 3 Magnus* 85.0 48 61 59 Andrew* 62.8 43 43 37 Schiehallion/Loyal* Various 36 8 -- Miller* 40.0 30 31 43 Other Various 123 110 124 ------ ------ ------ Total UK offshore 540 470 391 Onshore Wytch Farm* 50.5 40 48 45 Other Various -- -- 1 ------ ------ ------ TOTAL UK 580 518 437 ------ ------ ------ Rest of Europe Norway (b) Various Various 98 103 113 Netherlands Various Various 2 2 2 ------ ------ ------ TOTAL REST OF EUROPE Various 100 105 115 ------ ------ ------ </TABLE> 12
<TABLE> <CAPTION> Net production -------------------- Field or Area Interest 1999 1998 1997 ------------- -------- ----- ----- ----- (%) (thousand barrels per day) <S> <C> <C> <C> <C> <C> Rest of World Egypt October 30.4 35 30 38 Other Various 95 75 66 Colombia Cusiana/Cupiagua* 19.0 66 54 33 Canada (b) Various Various 56 68 61 Trinidad Various 100 49 47 48 Azerbaijan Azeri-Chirag-Gunashli* 34.1 32 16 -- Venezuela Various Various 30 31 21 Australia Various 16.7 23 30 28 Other (b) Various Various 21 34 43 ------ ------ ------ TOTAL REST OF WORLD 407 385 338 ------ ------ ------ TOTAL GROUP 1,891 1,841 1,758 ====== ====== ====== Equity-accounted entities Abu Dhabi (d) Various Various 113 124 118 Argentina Various Various 41 45 48 Other Various Various 16 39 6 ------ ------ ------ TOTAL EQUITY-ACCOUNTED ENTITIES 170 208 172 ------ ------ ------ TOTAL GROUP AND BP AMOCO SHARE OF EQUITY-ACCOUNTED ENTITIES 2,061 2,049 1,930 ====== ====== ====== </TABLE> <TABLE> <CAPTION> ESTIMATED NET PROVED RESERVES (a) December 31, 1999 ------------------------------------------------------ Rest of Rest of SUBSIDIARY UNDERTAKINGS UK Europe USA World Total ------ ------ ------ ------ ------ (millions of barrels) <S> <C> <C> <C> <C> <C> 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 ====== ====== ====== ====== ------ EQUITY-ACCOUNTED ENTITIES 1,037 ------ TOTAL GROUP AND BP AMOCO SHARE OF EQUITY-ACCOUNTED ENTITIES 7,572 ====== </TABLE> 13
NATURAL GAS (a)(e) PRODUCTION <TABLE> <CAPTION> Net production -------------------- Field or Area Interest 1999 1998 1997 ------------- -------- ----- ----- ----- (%) (million cubic feet per day) <S> <C> <C> <C> <C> <C> Lower 48 onshore (b) San Juan Coal* Various 427 408 383 Tuscaloosa Various 175 156 126 Hugoton* Various 162 170 242 Altura Various 118 143 108 Arkoma Various 111 129 142 Wamsutter* 70.5 92 87 84 Moxa Arch* 41.0 77 110 69 Anschutz Ranch East* Various 67 26 80 Jonah* 79.1 57 27 5 Whitney Canyon Various 52 53 53 Other Various 356 434 657 ------ ------ ------ Total Lower 48 onshore 1,694 1,743 1,949 Alaska Various Various 10 10 12 Gulf of Mexico (b) Ram Powell (VK 912) 31.0 72 50 3 Matagorda Island 623* 44.0 99 97 70 Other Various 400 421 415 ------ ------ ------ TOTAL USA 2,275 2,321 2,449 ------ ------ ------ UK offshore (b) Bruce* 37.0 175 182 202 West Sole* 100.0 97 102 99 Ravenspurn South* 100.0 87 103 132 Armada 18.2 77 74 14 Braes Various 76 69 76 East Leman* 48.4 42 71 49 Amethyst* 45.4 42 57 64 Other Various 699 594 781 Onshore Various Various 6 6 6 ------ ------ ------ TOTAL UK 1,301 1,258 1,423 ------ ------ ------ Netherlands P/18-2* 48.7 63 73 42 Other Various 48 68 84 Norway Various Various 53 59 69 ------ ------ ------ TOTAL REST OF EUROPE 164 200 195 ------ ------ ------ Canada (b) Kirby* 71.9 132 139 85 Leismer* 54.2 64 49 45 Marten Hills* 96.0 56 56 53 Ricinus* 70.0 54 59 66 Brazeau River Gas* 70.0 41 52 44 Other Various 342 412 471 Trinidad Mahogany* 100 367 14 -- Immortelle* 100 207 125 105 Flamboyant* 100 92 187 121 Other 100 115 113 104 Australia Various 16.7 215 211 202 Sharjah Sajaa* 40.0 168 157 134 Other Various 38 62 97 Indonesia Pagerungan 40.0 103 108 129 Other (b) Various Various 69 64 22 ------ ------ ------ TOTAL REST OF WORLD 2,063 1,808 1,678 ------ ------ ------ TOTAL GROUP 5,803 5,587 5,745 ====== ====== ====== </TABLE> 14
NATURAL GAS (a)(e) <TABLE> <CAPTION> Net production -------------------- Field or Area Interest 1999 1998 1997 ------------- -------- ----- ----- ----- (%) (million cubic feet per day) <S> <C> <C> <C> <C> <C> Equity-accounted entities Argentina Various Various 145 128 19 Other Various Various 119 93 94 ----- ----- ----- TOTAL EQUITY-ACCOUNTED ENTITIES 264 221 113 ----- ----- ----- TOTAL GROUP AND BP AMOCO SHARE OF EQUITY-ACCOUNTED ENTITIES 6,067 5,808 5,858 ===== ===== ===== </TABLE> <TABLE> <CAPTION> ESTIMATED NET PROVED RESERVES (A) December 31, 1999 ------------------------------------------------------ Rest of Rest of SUBSIDIARY UNDERTAKINGS UK Europe USA World Total ------ ------ ------ ------ ------ (billions of cubic feet) <S> <C> <C> <C> <C> <C> 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 ====== ====== ====== ====== ------ EQUITY-ACCOUNTED ENTITIES 1,724 ------ TOTAL GROUP AND BP AMOCO SHARE OF EQUITY-ACCOUNTED ENTITIES 35,526 ====== </TABLE> - ---------- (a) Net proved reserves of crude oil and natural gas, stated as of December 31, 1999, exclude production royalties due to others, and include minority interests in consolidated operations. (b) In 1999, BP Amoco 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 Amoco 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. In 1997 BP Amoco sold, purchased or swapped a number of interests in the North Sea. These transactions increased our interest in a number of fields, including Ula, Gyda and Draugen in Norway and Amethyst and Ravenspurn North in the UK sector of the Southern North Sea. We also sold certain assets in the USA. Late in 1997, BP Amoco purchased a 10% interest in A O Sidanco, a Russian oil company, for which reserves are included within associated undertakings in 1999 and 1998. (c) BP Amoco has a 51.2% interest in the oil rim and a 13.8% interest in the gas cap. (d) The BP Amoco Group holds proportionate interests, through associated undertakings, in onshore and offshore concessions in Abu Dhabi expiring in 2014 and 2018, respectively. (e) Natural gas production volumes exclude gas consumed in operations. 15
UNITED STATES We are the largest producer of both oil and natural gas in the USA. Our 1999 US oil production averaged 804,000 barrels per day (b/d). This was a decline of 3% from 1998. Approximately 50% of our 1999 oil production came from Alaska, 32% from onshore Lower 48 states, and the remainder from the Gulf of Mexico. Our 1999 US natural gas production averaged 2,275 million cubic feet per day (mmcf/d), with an additional 94 mmcf/d from the equity-accounted entity, Crescendo Resources LP. This was down 1% from 1998. Our current principal producing fields in Alaska are in production decline. Several developments are either planned or under construction to temper this decline and enable Alaska to remain a major producing area for the foreseeable future. Elsewhere in the USA, we expect increases in production in the Gulf of Mexico to more than offset the decline onshore. Development expenditure in the USA (excluding pipelines) during 1999 was $1,212 million, compared with $1,670 million in 1998. In Alaska, our production of crude oil declined from 454,000 b/d in 1998 to 405,000 b/d in 1999. Natural gas production remained at 10 mmcf/d, the same level as in 1998. The current status of activity in Alaska is as follows: -- Development is ongoing to temper the production decline at Prudhoe Bay, the largest producing field in Alaska. The decline is projected to moderate in 2000 due to a number of near-term projects. These include the Miscible Injectant Expansion project which is projected to add 18,000 b/d (gross) of incremental production. Further, we are continuing the infill drilling programme, a mixture of new wells, rig side-tracks and coiled tubing drilled side-tracks, which is expected to add 22,000 b/d (gross) of incremental production. Additionally, we are increasing our spending on satellite field developments around Prudhoe Bay. -- In line with BP Amoco's commitment to grow the natural gas business, recent actions taken in Alaska include the formation of a new business unit to investigate all options to commercialize Alaskan gas. These options include export by pipeline, LNG and Gas-to-Liquids (GTL) technology. BP Amoco has committed to build a GTL test facility in Alaska. -- The Badami oil field (BP Amoco 70% and operator) came on stream in the third quarter of 1998. In February 1999, we temporarily suspended production in order to perform well work and analyze additional reservoir data. The field was restarted in early May and has continued in production at around 3,000 b/d gross compared with an expected rate of around 35,000 b/d. The Badami partners are reviewing options for further development in the Badami Unit and the surrounding area. To reflect these factors, we have provided $100 million against the carrying value of the property. -- The first phase of development of the Northstar field (BP Amoco 98% and operator) began in 1998 with module construction in Alaska. All major construction permits were received in 1999. We are currently building the gravel island where field facilities will be located, installing pipelines, and continuing module construction for the Summer 2000 and 2001 sealifts. We expect production to commence in late 2001 with a plateau rate of 52,000 b/d net. Onshore in the Lower 48 states, BP Amoco's production of crude oil, condensate, NGL and natural gas averaged 569,000 boe/d, including 17,000 boe/d from equity-accounted entities, down from 577,000 boe/d in 1998. Production comes from a large number of fields situated principally in the states of Colorado, Kansas, Louisiana, New Mexico, Oklahoma, Texas and Wyoming. In March 2000, BP Amoco and Shell Exploration and Production Company (Shell) announced the sale of their interests in Altura Energy Ltd (Altura), a US onshore oil-producing joint venture. Altura is a joint venture between BP Amoco (approximately 64%) and Shell (approximately 36%). Altura's 1999 production of approximately 150,000 boe b/d gross came from over 6,000 (owned or operated) producing wells in large secondary/tertiary recovery projects. 16
Our production in the Lower 48 states is predominantly natural gas. Major areas of activity include the following: -- Overthrust Belt, Moxa Arch and Wamsutter -- southern Wyoming -- San Juan Basin coal and conventional gas fields-- Colorado and New Mexico -- Hugoton and Panoma fields -- western Kansas -- Anadarko Basin - Oklahoma and Texas panhandles -- Arkoma Basin -- eastern Oklahoma -- Cotton Valley trend -- east Texas -- Tuscaloosa trend -- Louisiana. Through divestments and property exchanges, we have focused our onshore producing activities in areas where we are a leading producer. -- Effective December 31, 1999 BP Amoco and Repsol YPF dissolved Crescendo Resources LP, a jointly owned production, gathering and processing partnership, with BP Amoco acquiring a majority of Repsol YPF's interest in the assets. The purchase is consistent with BP Amoco's strategy to grow its leadership position in core North American natural gas assets and has strengthened our position in the Anadarko basin by increasing our natural gas production by around 90 mmcf/d. -- We divested ownership interests in three non-core enhanced recovery oil production assets during the second half of 1999: Beaver Creek (Wyoming) in August and Bairoil (Wyoming) and Rangely (Colorado)in November. The combined 1999 net production for the three properties was 11,500 boe/d. In the Gulf of Mexico, combined offshore oil and natural gas production increased from some 215,000 boe/d net in 1998 to 237,000 boe/d in 1999. Significant 1999 development activity in the Gulf of Mexico included the following: -- In the Mars field (BP Amoco 28.5%) we brought three new wells online. Production increased to 167,000 boe/d gross with facility debottlenecking and a peak production of 182,000 boe/d gross was reached in November, 1999. Facility expansion work continued to allow the subsea tieback of the Europa field in early 2000. -- In the Troika field (BP Amoco 33.3% and operator) production from the fifth well commenced in March 1999. Total production for all of the wells in 1999 averaged 132,000 boe/d gross as compared with 77,000 boe/d gross during 1998. The peak daily production rate for the year was 155,000 boe/d gross. -- Initial development of the Ram Powell field (BP Amoco 31%) was completed in 1999. Production averaged nearly 97,000 boe/d gross in 1999. -- The Ursa oil and natural gas field (BP Amoco 22.7%) commenced production in March 1999 from the largest tension-leg platform installed in the Gulf of Mexico. Two wells were completed, with the Ursa A-7 well producing at a rate in excess of 50,000 boe/d. Drilling and completion continues toward a peak production rate of some 200,000 boe/d gross in 2001. -- Development of the Hoover/Diana oil and natural gas fields (BP Amoco 33.3%) continued in 1999. This simultaneous development of two fields, with combined resources of 300 mmboe gross, represents BP Amoco's deepest water project to date. All facilities are on location and in the commissioning phase. Three wells have been completed with five additional wells scheduled for 2000. First production is targeted for mid-2000. -- Production from our Marlin development (BP Amoco 86% and operator) has been delayed owing to a well design problem which is being investigated. 17
UNITED KINGDOM We are the largest producer of both oil and natural gas in the UK. Our 1999 UK oil production of 580,000 b/d was 62,000 b/d higher than in 1998, as the increase in production from more recently developed fields more than offset declines in mature fields. Our UK natural gas production increased 3% from 1,258 mmcf/d in 1998 to 1,301 mmcf/d in 1999. Increased production from the Eastern Trough Area Project (ETAP) more than offset the decline at older UK offshore fields. Our 1999 development expenditure in the UK (excluding pipelines) was $676 million, compared with $1,432 million in 1998. Significant 1999 activity included the following: -- Production from the first phase of the Foinaven field (BP Amoco 72% and operator), built up to its plateau level of 85,000 b/d gross. Located in waters 500 metres deep, Foinaven was the first producing oil field in the deep water Atlantic Margin, west of the Shetland Islands. Oil flows from the well through flexible flow lines to a floating production storage and offshore loading vessel (FPSO) and is then carried by dedicated shuttle tanker to the Flotta oil terminal, Orkney. -- Schiehallion (BP Amoco 33.4% and operator) and Loyal (BP Amoco 50% and operator), which together comprise our second west of Shetland development, commenced production in the third quarter of 1998. Several new production records for the fields were set in 1999 and maximum daily production was in excess of 170,000 b/d gross. Average daily production for 1999 was 95,000 b/d gross. Production in 2000 is expected to increase to around 130,000 b/d. -- ETAP production continued to build-up throughout 1999, with plateau production levels of 265,000 boe/d gross (135,000 boe/d net) achieved in the fourth quarter. The development comprises seven initial fields -- Marnock, Machar, Mungo and Monan (BP Amoco 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. -- We established first production in late 1998 from the Phase 2 expansion of the Bruce field (BP Amoco 37% and operator). This expansion involves subsea development of the western area of the field, linked by a bundled pipeline to a new steel platform. During 1999 development of the Bruce field included completion of five platform/subsea wells and progress towards commissioning Booster Compression on the Bruce platform in 2000. Net production for 1999 was 51,000 boe/d compared with 42,000 boe/d in 1998. -- In November 1999, we completed the sale of our interests in the non-operated Scott (BP Amoco 13.496%), and Telford Fields (BP Amoco 20.16%), and block 15/22 (BP Amoco 26%) which lie in the outer Moray Firth of the North Sea. Average production for the fields during 1999 was approximately 18,000 boe/d. -- In 1999, the Harding field (BP Amoco 70%) continued to produce at plateau production rates. The first well into the south east reservoir was brought on stream during the second quarter of 1999 and produced steadily at 7,500 b/d gross. During the third quarter the production facilities were successfully de-bottlenecked and in November a record production rate of 100,000 b/d gross was achieved. REST OF EUROPE Our oil production in Norway decreased from 103,000 b/d in 1998 to 98,000 b/d in 1999 as a result of natural field decline. Net production was 38,000 b/d from Draugen (BP Amoco 18.4%), 24,000 b/d from Valhall (BP Amoco 28.1% and operator), 19,000 b/d from Ula (BP Amoco 80% and operator) and 17,000 b/d from Gyda (BP Amoco 56% and operator). In the Netherlands, our net production decreased to 111 mmcf/d from 141 mmcf/d in 1998. BP Amoco is supplementing its long-standing production operations with the expansion of its Peak Gas Installation, a natural gas storage facility. This expansion, which became operational in 1999, increases the capacity of 850 mmcf/d by 50% to 1,270 mmcf/d with the potential for further capacity increase. 18
REST OF WORLD The Group's net share of oil production from the Rest of World increased from 385,000 b/d in 1998 to 407,000 b/d in 1999. This excluded 170,000 b/d from associated undertakings in 1999, of which 113,000 b/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 1999 were Australia, Argentina, Azerbaijan, Bolivia, Canada, China, Colombia, Egypt, Indonesia, Russia, Sharjah, Trinidad and Venezuela. Our share of natural gas production from the Rest of World increased 14% from 1998, averaging 2,063 mmcf/d in 1999. In addition, in 1999 production from associated undertakings amounted to 170 mmcf/d. The largest part of the 1999 production came from Trinidad and Tobago, with the remainder from Argentina, Australia, Bolivia, Canada, Colombia, Egypt, Indonesia and Sharjah. Development expenditure in the Rest of World (excluding pipelines) amounted to $956 million in 1999, compared with $1,569 million in 1998. In 1999, this expenditure was primarily in Canada, Colombia, Trinidad and Venezuela: - -- In Canada, we divested our heavy and conventional oil properties for approximately $1.1 billion in October 1999. The sale represents approximately 60,000 boe/d net of oil equivalent production. The divested assets included substantial heavy oil operations in the Primrose, Wolf Lake and Wabasca areas near Edmonton, Alberta. Also in Canada we sold our significant 2-D and 3-D seismic data base to a seismic broker, retaining the right to access this data on favourable terms. The divestment of our marginal heavy oil business will enable us to give greater focus on our core natural gas business. - -- In Colombia, production of the Cusiana/Cupiagua development (BP Amoco 19% and operator) has reached a plateau of approximately 69,000 b/d net. The Cusiana field is now in decline and the Cupiagua field is expected to reach its peak production in 2000. Colombia has now identified some well-defined projects with the aim of sustaining production; some of these projects are extensions in the Cusiana/Cupiagua area and some others are in the Recetor and Piedemonte licences. - -- We have been engaged in exploration and production activities in Trinidad and Tobago since 1961. We hold a 100% interest in 121 tax and royalty licences and a partial interest in a production sharing contract on a recently acquired licence. Our Trinidad operations are in a transition from primarily oil to a balance of oil and natural gas activities, and we hold domestic sales contracts for up to 700 mmcf/d in Trinidad and Tobago. We are the sole supplier of the initial natural gas requirement of the liquefied natural gas plant belonging to the Atlantic LNG Company of Trinidad and Tobago, in which we hold a 34% interest (see Midstream discussion below). Drilling activity continued in the Mahogany field to develop oil and natural gas. Our total hydrocarbon production during 1999 averaged 183,000 boe/d net, an increase of 66,000 boe/d from 1998. In 1999, crude and condensate production increased by 4% to 48,900 b/d net, and natural gas sales increased by 85% to 779 mmcf/d net, a result of increased local gas demand and start up of the Atlantic LNG plant operation. The installation of the Amherstia platform commenced in late 1999 and is planned to come on stream in 2000 to feed additional domestic gas sales within Trinidad and Tobago. - -- In Venezuela, we announed the disposal of our 100% interest in the Pedernales reactivation licence in November 1999, subject to PDVSA approval. BP Amoco retains an interest in other production reactivation and exploration blocks. The most prolific of the reactivation blocks is Jusepin (BP Amoco 45%), currently producing 30,000 b/d gross. Secondary recovery projects are underway in the Jusepin field with the aim of maintaining and expanding production levels. Retained exploration blocks also include Punta Pescador (BP Amoco 50%) and Guarapiche (BP Amoco 75%). The Azeri-Chirag-Gunashli (ACG) early oil project in the Caspian Sea, offshore Azerbaijan (BP Amoco 34.1%) achieved plateau production in 1999 of in excess of 100,000 b/d gross. In April 1999, the Western Export Route Pipeline through Georgia was commissioned and oil is currently being exported from ACG through two pipelines (the second pipeline being through Russia). In June 1999, BP Amoco was appointed operator of the Azerbaijan International Operating Company (AIOC) responsible for operation and development of the ACG complex. Several additional phases of development are planned. 19
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. Gupco operates seven production sharing contracts in the Gulf of Suez and Western Desert, encompassing more than 40 fields. During 1999, Gupco produced almost 290,000 b/d (130,000 b/d net), about 37 percent of Egypt's oil production, as well as 78 mmcf/d (35 mmcf/d net) of natural gas. In early 1999, BP Amoco 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 Amoco will invest $450 million by 2005 to develop new reserves, maintain production, and prolong the life of the fields. Over $50 million of this spending had been completed by year end 1999, and another $120 million will be spent in 2000. BP Amoco entered the Nile Delta in the early 1990's, in a variety of partnerships with AGIP, Egyptian General Petroleum Corporation and others. The Ha'py field was brought on stream in early 2000 and the Baltim and Temsah natural gas fields are expected to start-up in late 2000 or early 2001. Collectively, we have agreements in place to supply 250 mmcf/d to the domestic Egyptian market from these and other Nile Delta fields. We continue to actively pursue natural gas export opportunities in the Eastern Mediterranean and we have the public support of the Government of Egypt. Through our equity-accounted investments in Empresa Petrolera Chaco S.A. (Chaco) (BP Amoco 30%) and Pan American Energy (PAE) (BP Amoco 60%), we are the second largest energy producer in the Southern Cone of South America. In 1999, these entities produced 45,000 b/d of oil and 170 mmcf/d of natural gas (net to BP Amoco) 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. Pan American Energy's regional midstream and downstream natural gas position was enhanced during the year through the ratification of the Cruz del Sur gas pipeline concession (BP Amoco 18%). This pipeline will transport natural from Buenos Aires to Montevideo and is the first part of a integrated pipeline system which is ultimately intended to serve the major gas markets in southeast Brazil. MIDSTREAM ACTIVITIES OIL AND NATURAL GAS TRANSPORTATION The Group has direct or indirect interests in certain crude oil transportation systems, the principal 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. 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 Amoco 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 1999, TAPS transported production from Prudhoe Bay and the other North Slope fields averaging 1.08 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. The use of US-built and US-flagged ships is required when transporting Alaskan oil to markets in the USA and abroad. In accordance with this, BP America Inc. has a chartered fleet of US-flagged tankers to transport Alaskan crude oil to markets. In 1999, the Alaska Tanker Company (ATC) was formed to be the single operator for this fleet. Over the next few years, we plan to begin replacing our US-flagged fleet as existing ships are retired in accordance with the Oil Pollution Act of 1990. For discussion of the Oil Pollution Act of 1990, see Regulation of the Group's Business -- Environmental Protection. For a discussion of the proceedings arising from the Exxon Valdez oil spill, see Item 3 -- Legal Proceedings. 20
The Forties Pipeline System in the UK (BP Amoco 100%) is an integrated oil and natural gas liquids transportation and processing system which 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 1999, average throughput was approximately 943,000 b/d, compared with 880,000 b/d in 1998, and transported its five billionth barrel. A Marine Vapour Recovery project was completed in 1999 and this will lead to a substantial reduction in Volatile Organic Compound emissions. BP Amoco 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 NGLs for export or for local industry with gas entering the UK National Transportation System. In 1999 CATS handled throughput of 1.2 bcf/d with volumes at the end of the year reaching 1.7 bcf/d. BP Amoco, 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 200,000 b/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. An Inter-governmental Agreement between Turkey, Georgia and Azerbaijan to support this pipeline was signed on November 18,1999. LIQUEFIED NATURAL GAS In Trinidad and Tobago, we have a 34% interest in the Atlantic LNG plant and are the sole supplier of natural gas to the first train of the plant. An export contract of some 440 mmcf/d was established in 1999 for deliveries to the New England region of the USA and Spain from the first train of the plant. Gas sales commenced in February 1999 and averaged 246 mmcf/d per day for the year. Subject to government and partner approval, the facilities are expected to be expanded by the addition of a second and a third train at the plant. It is anticipated that BP Amoco will supply the additional natural gas volumes to the expanded facilities. We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction Company (ADGAS), which in 1999 supplied 5.2 million tonnes of LNG. In Australia, our share of LNG from the North West Shelf natural gas development (BP Amoco 16.7%) remained in line with that of the previous year at 1.3 million tonnes (approximately equivalent to 180 mmcf/d of natural gas). GAS AND POWER MARKETING AND TRADING We are one of the largest producer-marketers of natural gas in North America. Our 1999 gas sales volumes averaged 5.4 bcf/d from the USA and Canada. This consisted of 3.4 bcf/d from BP Amoco producing operations (including royalty volumes we marketed under terms of our lease agreements), plus supplies we purchased from third parties. As a result of the deregulation of the US natural gas markets since the late 1980s, approximately 75% of our North American natural gas production is now sold pursuant to short term gas contracts which are renegotiated on a monthly, yearly or other short term basis, thereby allowing us flexibility in production and distribution. As the North American energy markets continue to evolve, we are enhancing our current positions in the upstream, midstream and downstream natural gas businesses. 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 around 170 producers in the Western Canada Sedimentary Basin. It markets 1.45 bcf/d of gas a day across North America. We also reached agreement with Nova Scotia Resources (Ventures) Limited to market, on behalf of the Provincial Crown Corporation, 45 mmcf/d of natural gas production flowing from the Sable Offshore Energy Project located offshore Nova Scotia. Under the agreement, we will focus on marketing the gas primarily in New England and the north-eastern states of the USA. BP Amoco's policy toward natural gas price risk in the North American markets is described in Item 9A -- Quantitative and Qualitative Disclosures about Market Risk. 21
BP Gas, a UK natural gas marketing company, started trading in 1996. Its principal business is natural gas sales to industrial, commercial and power generation customers in the UK, as well as gas sales to continental Europe. In addition, we provide facilities and combined heat and power development and contract energy management services to industrial customers in the UK. The significance of long-term gas supply contracts with large customers such as Centrica, the prices of which are typically indexed against oil or electricity, has been declining as BP Gas takes advantage of increasingly liquid UK gas markets to make more short-term sales to commercial and industrial companies. The breakdown of gas sale arrangements in 1999 was as follows: 33% of production sold to Centrica, 24% pursuant to other long-term arrangements, and 43% in the commercial and industrial and spot markets. The main source of gas is BP Amoco's equity share of gas from UK North Sea fields. The Company disposed of its 50% interest in Beacon Gas Limited, a retail distributor of natural gas to domestic customers, during 1999, consistent with its focus on business-to-business marketing rather than retail distribution of natural gas in the UK. Construction of a 400 megawatt capacity gas-fired power plant (BP Amoco 60%) at Great Yarmouth in the UK continued during 1999 and is due to be commissioned in 2001. The Company also received Government consent to construct a 500 megawatt combined cycle gas turbine power plant at the Baglan Energy Park in South Wales. Online services to natural gas customers were developed including an online gas trading service for non-fixed price customers. In the Rest of Europe, we have a 25.5% interest in Ruhrgas, Germany's largest gas distribution company. In 1997 BP Amoco signed a 15-year agreement to supply 15 billion cubic metres of natural gas valued in excess of $1 billion to Ruhrgas, commencing October 1, 1998. We supply this gas from our UK North Sea fields, delivered via the Interconnector, which is described below. The Interconnector is a 240-kilometre, 40-inch subsea natural gas pipeline linking the UK national grid system at Bacton in Norfolk to the continental grid system at Zeebrugge in Belgium. Construction work began in late 1996, and first operation of the pipeline was in October 1998. We are one of ten international energy companies with shareholdings in the Interconnector, which has a shipping capacity of 1.9 bcf/d (BP Amoco 10%). In Spain, where the market is being liberalized in common with other EU states, we were the first foreign company to secure a licence permitting us to market natural gas to industrial consumers. During the last quarter of 1999 we made encouraging progress in the marketing of future reserves from Australia, Trinidad and the Caspian Sea. Plans were announced in September 1999 to create a Gas and Power business to market our substantial upstream natural gas reserves and develop a leading gas and power marketing and trading business. The Gas and Power business stream will be reported as a business segment from January 1, 2000. The new stream will be responsible for our existing world-wide gas marketing and development activities, including gas-fired power generation. 22
REFINING AND MARKETING Our Refining and Marketing business is responsible for the supply and trading, refining, marketing and transportation of crude oil and petroleum products to wholesale and retail customers, and the wholesale marketing of NGL in the USA and Canada. BP Amoco markets its products in about 100 countries. It has operations in Europe, the USA and Australasia and in parts of South East Asia and Africa. <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ----- ----- ----- ($ million) <S> <C> <C> <C> Turnover (a)............................................. 62,893 48,437 67,704 Total replacement cost operating profit.................. 1,840 2,564 2,292 Total assets............................................. 27,248 21,029 24,055 Capital expenditure and acquisitions..................... 1,634 1,937 1,824 ($ per barrel) Indicative industry global refining margin (b)........... 0.91 1.74 1.81 </TABLE> - ---------- (a) Excludes BP Amoco's share of joint venture turnover of $17,117 million in 1999, $15,080 million in 1998, and $16,692 million in 1997. (b) The indicative industry global refining margin is a weighted average of global margins for the whole refining industry and is calculated by BP Amoco. It reflects the margins generated by a standard cracking refinery, running similar quality crudes, to similar yields, located in each refining market. The weighting used reflects the presence of BP Amoco's refineries in these markets - principally those of the USA, Europe, Australasia, Southern Africa and Singapore. Refining and Marketing aims to manage a portfolio of assets which are believed to be 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 created a top-tier player in refining and marketing. We are one of the leading refiners and marketers of gasoline and hydrocarbon products in the USA, and a market-leader in premium gasoline. Overall we have a strong geographic position with the largest market share for retail sales east of the Rocky Mountains, including first or second position in some 20 states. We also have extensive retail and commercial businesses in the UK, the Rest of Europe, Australasia, Africa and South East Asia. Worldwide, BP Amoco continues to be a leading marketer of fuels, served by a global refining network with key refineries among the top performers in their regions. The prevailing economic conditions have driven a considerable re-basing of business activities outside the USA not directly impacted by the merger. This activity has necessitated a reduction in employee numbers; within the Refining and Marketing business some 5,100 people, or 15% of the workforce, left during 1999. At the end of 1999 some 45,250 people were employed worldwide by the business. As part of the Federal Trade Commission's approval process for the merger, BP Amoco undertook to complete the sale of nine terminals formerly owned by Amoco in the Southeast of the USA where there was an overlap with existing BP terminals. In addition, in order to resolve anti-trust concerns relating to the sale of gasoline, BP and Amoco agreed to the divestiture of 134 service stations in six states where there were ownership overlaps. The divestitures were completed during 1999. In the UK and the rest of Europe, during 1999, BP Amoco's refining and marketing operations in fuels and lubricants were operated as part of a joint venture (BP/Mobil joint venture) with ExxonMobil Corporation (ExxonMobil). Our international aviation, marine, oil trading and shipping activities are excluded from the joint venture. Under the terms of the joint venture, BP Amoco operates and has a 70% interest in the fuels refining and marketing operation, and ExxonMobil operates and has a 51% interest in the lubricants business. 23
In December 1999, we agreed with ExxonMobil the principles under which the BP/Mobil European fuels and lubricants joint venture would be dissolved in response to the European Commission's authorization of the Exxon and Mobil merger. Under the agreement - which is subject to a number of approvals from national governments and appropriate employee consultation - BP Amoco will purchase Mobil's 30% interest in the fuels business for about $1.5 billion, subject to adjustments. In addition, the two companies will divide the assets of the lubricants business broadly in line with their equity stakes (51% Mobil, 49% BP Amoco). In February 2000, the European Union's Merger Task Force gave its approval to the dissolution as proposed. REFINING In refining, our key objective is to operate an advantaged refining system more profitably than those of our competitors. Advantaged characteristics relate to supply - the refinery's position in relation to the market; clean fuels - how the refinery supports our clean fuels strategy; integration value - how the refinery adds value by virtue of integration with other parts of the Group's business. A consequence of this objective will be to reduce the ratio between our own refining supply and the volumes we market to between 60 and 70% from the level of around 90% existing in 1999. As a first step, the Alliance refinery in Louisiana, USA, has been offered for sale. There will continue to be focus on reducing operating costs and optimizing yields. In addition to the Alliance refinery, BP Amoco owns and operates six refineries in the USA: Texas City, Texas; Whiting, Indiana; Toledo, Ohio; Mandan, North Dakota; Yorktown, Virginia; and Salt Lake City, Utah. BP Amoco's refinery at Lima, Ohio, was sold in mid-1998. In Europe, as operator of the fuels business of the BP/Mobil joint venture, we operate seven fuels refineries on behalf of the joint venture. These are Bayernoil (Germany), Castellon (Spain), Coryton (UK), Grangemouth (UK), Lavera (France), Mersin (Turkey) and Nerefco (the Netherlands). Additionally, BP Amoco has an interest in the Reichstett refinery in France. All the refineries are wholly-owned by BP Amoco or Mobil, except for Bayernoil, Mersin, Nerefco and Reichstett where BP Amoco's and Mobil's combined interest is 55%, 69%, 69% and 17%, respectively. Mobil's refinery at Gravenchon (France), which is primarily a lubricants refinery, and BP Amoco's two lubricants base oil refineries in France and Germany are operated by Mobil on behalf of the joint venture. BP Amoco's UK base oil refinery at Llandarcy was closed in 1998 as part of a major restructuring of the lubricants business. In the rest of the world we operate three other principal refineries: at Brisbane and Kwinana in Australia and in Singapore. We also have interests in three other refineries: Mombassa in Kenya, Durban in South Africa and Whangerei in New Zealand. The following tables set out by area the crude oil and other feedstocks processed in the years 1997 through 1999 by the BP Amoco 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 1999 1998 1997 ----- ----- ----- (thousand barrels per day) <S> <C> <C> <C> United Kingdom (a)....................................... 271 296 299 Rest of Europe (a)....................................... 540 551 583 United States............................................ 1,340 1,489 1,600 Rest of World............................................ 371 362 373 ----- ----- ----- 2,522 2,698 2,855 For BP Amoco by others................................... 19 13 12 ----- ----- ----- Total.................................................... 2,541 2,711 2,867 ===== ===== ===== REFINERY CAPACITY UTILIZATION Crude distillation capacity at December 31, (a) (b)...... 2,801 2,815 2,937 Crude distillation capacity utilization (c).............. 95% 94% 96% </TABLE> - ---------- (a) Includes the BP Amoco share of the BP/Mobil joint venture. 24
(b) The crude distillation capacity figures are based on gross rated capacity which assumes no loss of capacity due to shutdowns. The figures for 1998 reflect the disposal of the Lima refinery in mid-1998. The figures for 1997 reflect the impact of the BP/Mobil joint venture for those countries for which implementation was completed by the end of 1997. The implementation of the joint venture did not have a material impact on BP Amoco's overall crude distillation capacity in Europe. (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 Amoco refineries (net rated capacity). In 1999, we operated our refineries in the USA at an average of 95% of net rated capacity (1998 and 1997, 95%), our European refineries at 94% (1998, 95% and 1997, 98%) and our refineries in the rest of the world at 96% (1998, 89% and 1997, 99%). In 1999, we continued our programme of upgrading refinery capability. The Toledo Repositioning Project was completed in April with start up of the new units at the refinery. This project, which includes a new coker and sulphur plant, makes the Toledo Refinery a leading competitor in the United States Midwest with the ability to utilize heavy sour crude for up to two-thirds of its crude input. Also during 1999 we commenced a project to allow low sulphur fuels production at our Brisbane refinery. Completion is scheduled for the end of 2000. Additionally, over $60 million was spent on projects during 1999 to deliver cleaner fuels throughout our refining system. Emissions of greenhouse gases (primarily carbon dioxide) were reduced by more than 3% compared with 1998, primarily through operational actions. Additional reductions are planned through continued energy efficiency improvements and participation in the internal BP Amoco trading programme. MARKETING We market a comprehensive range of refined oil products world-wide. These products include gasoline, gasoil, marine and aviation fuels, heating fuels, LPG, lubricants and bitumen. The following table sets out refined product sales by area. <TABLE> <CAPTION> Years ended December 31, ------------------------ SALES OF REFINED PRODUCTS (a) 1999 1998 1997 ----- ----- ----- (thousand barrels per day) <S> <C> <C> <C> Marketing sales: United Kingdom (b)(c).................................. 235 261 260 Rest of Europe (b)..................................... 794 769 752 United States.......................................... 1,542 1,504 1,465 Rest of World.......................................... 615 603 606 ----- ----- ----- Total marketing sales (d)................................ 3,186 3,137 3,083 Trading/supply sales (d)................................. 1,816 1,665 1,592 ----- ----- ----- Total refined products................................... 5,002 4,802 4,675 ===== ===== ===== ($ million) Proceeds from sale of refined products (b)............... 44,248 44,446 57,026 </TABLE> - ---------- (a) Excludes sales to other BP Amoco businesses. (b) Includes the BP Amoco share of the BP/Mobil joint venture. (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. 25
<TABLE> <CAPTION> Years ended December 31, ------------------------ MARKETING SALES BY PRODUCT 1999 1998 1997 ----- ----- ----- (thousand barrels per day) <S> <C> <C> <C> Aviation fuel............................................ 366 292 271 Gasolines................................................ 1,298 1,256 1,204 Middle distillates....................................... 765 796 780 Fuel oil................................................. 319 322 410 Other products........................................... 438 471 418 ----- ----- ----- Total marketing sales ................................... 3,186 3,137 3,083 ===== ===== ===== </TABLE> In marketing our aim is to grow our customer base, not only in existing markets but also in new markets - more customers in a bigger geographic spread. We are focusing on how we can increase the amount our customers spend with us, whether they be retail customers spending more on items in convenience stores or business customers spending more on value-added services and solutions. Our objective is therefore to create a more capital-efficient, higher-return business. In addition we recognize that our customers are demanding a wider choice of fuels - fuels which are cleaner and more efficient. In Retail, we envisage that there will be two distinct segments: fuels, which we intend to grow through franchises, dealers and jobbers; and a directly managed convenience store segment. We plan to expand our Retail business in a disciplined way through rigorous site selection for convenience or for fuels sales, and by concentrating direct convenience offers in our core metropolitan markets. <TABLE> <CAPTION> Years ended December 31, ------------------------ SHOP SALES (a) 1999 1998 1997 ----- ----- ----- ($ million) <S> <C> <C> <C> UK....................................................... 265 231 189 Rest of Europe........................................... 569 513 468 USA...................................................... 542 543 438 Rest of world............................................ 365 356 381 ----- ----- ----- Total.................................................... 1,741 1,643 1,476 ===== ===== ===== </TABLE> (a) Shop sales reported are sales through direct managed stations, franchisees and the BP Amoco share of shop alliances and joint ventures. Sales figures exclude VAT and lottery sales but include quick service restaurant sales. The sales include the BP Amoco share of the relevant sales within the BP/Mobil joint venture. Our retail network is concentrated in Europe and the USA, with established operations in Australasia and Southern Africa. Networks are being grown in China, Poland, Russia and Venezuela. BP Amoco is continuing to improve the efficiency of its retail network by reducing operating costs and improving customer service, through a process of regularly reviewing the network. Actions taken include divesting the non-strategic sites or networks, upgrading existing sites and investing in new sites. An essential element of this strategy is the development of convenience stores and the provision of related services. Such facilities are often provided through alliances or other arrangements with partners. This strategy is applied to all our retail networks, including those operated as part of the BP/Mobil joint venture. At December 31, 1999, there were approximately 28,300 BP and Amoco branded service stations world-wide, including those associated with the BP/Mobil joint venture. During 1999 we commenced implementation of two major environmental initiatives. In January 1999 we announced our 'Clean Cities' initiative to market cleaner fuels in 40 of the world's most polluted cities. During the year 15 launches of the initiative were undertaken in major cities around the globe including Paris, Atlanta, Chicago, and Istanbul. In April, we announced that around 200 of our service stations are to incorporate solar power - the largest single project of its kind ever undertaken. The first phase of the two-year programme is planned to consist of the installation of up to 400 solar panels on each canopy at service stations across eleven countries in a $50-million, 3.5-megawatt project, saving around 3,500 tonnes of carbon dioxide emissions every year. As a result of this project, BP Amoco will become one of the world's largest users of solar power. 26
At December 31, 1999 BP Amoco's retail network in the USA comprised some 16,300 service stations concentrated in the Midwest, East and Southeast. Developments in the USA during 1999 included: -- Divestment of the ProCare servicing and maintenance business was completed in September 1999. -- We agreed the extension of our alliance with Bovis Lend Lease, the construction and project management arm of Lend Lease Corporation, to develop and build new or remodelled service stations. In the UK and the Rest of Europe, BP Amoco's network covered about 8,200 service stations at December 31, 1999. Significant developments in Europe during 1999 included the following: -- We continued to develop our joint venture agreement with Safeway plc in the UK to redevelop some 100 sites incorporating a Safeway convenience store. By December 31, 1999, 39 such sites had been redeveloped. A further 36 are expected to be redeveloped in 2000 with the remainder of the programme to be completed in 2001. -- In France, Portugal and Spain we continued to develop co-operative retailing arrangements with our partners 8 a Huit, Modelo, and Speedy, respectively. -- In Poland and Russia, we continue to grow our retail network towards our target of 300 sites, with the construction of a further 37 retail sites during 1999 giving a total of 139 in these countries. -- As part of the continued drive to improve the asset base the retail network in Hungary was divested in early 1999. At December 31, 1999 BP Amoco's retail network in the rest of the world (primarily Australia, New Zealand, Southern Africa and South East Asia) comprised some 3,700 service stations. BP Amoco now has some 130 branded sites in the new markets of Venezuela, China and Japan. In addition, through the Amoxxo joint venture with Femsa, the Group has a network of 28 convenience stores in Mexico. 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-adding services and solutions; thus aiming to increase customer spend and growth in volumes at twice the market rate. Our Commercial and Industrial business operates in Australasia, Europe, South Africa and the USA. This business includes the supply of fuel, LPG, bitumen and, outside Europe, lubricants to industrial and domestic users. In Europe, the Group has a 49% interest in the lubricants activity operated by Mobil as part of the BP/Mobil joint venture. In 1999, we continued to reshape our Commercial and Industrial portfolio where we believe it to be appropriate: -- As part of a strategic review of our Bitumen business, we announced, in December 1999, the sale of our Bitumix road contracting business and bitumen supply terminals in New Zealand. -- We continued to develop our LPG business in Portugal, and as a result we have entered into a joint venture with Petrogal and Borealis to develop an LPG storage cavern facility at Sines. 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. During the last few years, the aviation business has strengthened its position in established markets and pursued opportunities in new or emerging markets. In 1999, BP Amoco's aviation business entered two new markets: Ivory Coast and Chile. The business now markets in some 87 countries. It is the third largest jet fuel supplier globally. BP Amoco's marine business sells ship's fuel and lubricants to a variety of customers including ship owners and operators, covering a wide range of vessels, from large oil tankers to small fishing boats. We operate a network of offices and supply points in more than 900 ports across 90 countries, reflecting the international nature of this marketing operation. In June 1999, we completed the divestment of our bunkering operations on the US West Coast. BP Amoco is continuing to develop the marine business, and is pursuing new market opportunities in Latin America, Asia and the Middle East. 27
In early 2000, BP Amoco's marine business announced that, in conjunction with other participants in this sector, it had signed an agreement to develop an industry-backed internet portal that will include an auction site with facilities to undertake purchase and sales transactions for marine fuels. The site is planned to become operational in mid-2000. SUPPLY AND MARKETING OF NGL In the USA and Canada, BP Amoco is engaged in the processing, fractionation and marketing of NGL, which consists of ethane, propane, butanes and pentanes extracted from natural gas. The majority of BP Amoco's NGL is marketed on a wholesale basis under annual supply contracts which provide for price redetermination based on prevailing market prices. Sales volumes of NGL for 1999 averaged 307,000 b/d (1998 318,000 b/d and 1997 298,000 b/d). NGL is also supplied to BP Amoco's chemical and refining activities. BP Amoco operates and/or owns natural gas processing facilities across all of North America having a total gross 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 Fort 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 1999, additional gas processing and fractionation capacity came on stream in Pascagoula, Mississippi to support the growth in BP Amoco's natural gas production in deepwater Gulf of Mexico. 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, NGL, carbon dioxide 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 eight major crude oil pipelines in the UK and the Rest of Europe and a further thirteen in the USA. Bulk products are transported between refineries and storage terminals by ship, barge, pipeline 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 four in the USA. We also have interests in a major natural gas pipeline, four NGL pipelines, two carbon dioxide pipelines and many smaller pipelines. In total, we have interests in some 33,000 kilometres of pipeline, of which about three-quarters are located in North America. The lateral pipelines to the main Destin natural gas trunk line from offshore in the Gulf of Mexico to Pascagoula, Mississippi and inland were completed in 1999. This allowed connections with a number of other gas pipelines and access to natural gas markets throughout the Southeast and the East coast of the USA. The Tri-States NGL line, which runs west from our facility in Pascagoula, Mississippi to Kenner, Louisiana, started up in March 1999. In February, 2000 BP Amoco announced that it exercised its right of first refusal to purchase Southern Natural Gas Company's one third interest in the Destin Pipeline. The purchase increases BP Amoco's interest in the pipeline to two thirds, with Tejas Destin L.L.C. continuing to hold the remaining interest. SHIPPING BP Amoco Shipping owns or operates an international fleet of crude and product tankers 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, 1999 the Group owned an international fleet of twelve tankers, totalling approximately 1.49 million deadweight tons (dwt). This included three Very Large Crude Carriers (VLCCs), four Medium Crude Carriers and five Product Carriers. All four of the Medium Crude Carriers were in lay-up at the end of the year. 28
Excluding BP Amoco companies in the USA, the Group had ten tankers (five VLCCs, four Medium Crude Carriers and one Product Carrier) and four barges, totalling approximately 2.17 million dwt, on long-term charter at December 31, 1999. BP Amoco companies in the USA had 20 tankers (two VLCCs and 17 Medium Crude Carriers and one Product Carrier), totalling approximately 2.39 million dwt on long-term charter along with two other barges on short-term charter. Four of the Medium Crude Carriers, totalling 0.65 million dwt, were in lay-up at the end of 1999. In addition, a large number of small coastal vessels are used by Group companies around the world. BP Amoco Shipping has contracted to bareboat charter three more VLCCs for delivery during 2000. CHEMICALS Our Chemicals business is a major producer of petrochemicals through subsidiaries and associated undertakings. BP Amoco 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, ------------------------ 1999 1998 1997 ----- ----- ----- ($ million) <S> <C> <C> <C> Turnover................................................. 9,392 9,691 11,445 Total replacement cost operating profit ................. 686 1,100 1,530 Total assets............................................. 13,021 12,562 12,141 Capital expenditure and acquisitions..................... 1,215 1,606 1,145 (thousand tonnes) Production (a) .......................................... 21,853 20,570 19,491 </TABLE> (a) Includes BP Amoco's share of associated undertakings and other interests in production. Chemicals margins are driven by the economics of supply and demand and, as a result, are cyclical in nature. An illustration of this is the industry integrated ethylene/low density polyethylene cash margin. This rose from 523 Deutschmarks (DM) per tonne in 1996 to 890 DM/tonne in 1997, then fell to 819 DM/tonne in 1998 and 666 DM/tonne in 1999. In 2000, the chemical industry's external environment is expected to be similar to that faced in 1999. While a pick-up in the growth of economies in Europe and Asia should lead to higher demand, new capacity coming on stream will increase supplies and competitive pressure on margins. Our strategy is to create competitive advantage in petrochemicals through adding value to Group hydrocarbons, industry cost leadership, world-leading technology, premier market positions, and a bias to higher growth products. As the petrochemicals arm of an oil major, a key element of our competitive advantage comes through adding value to Group hydrocarbons, notably by combining feedstock, refining and chemical processing on large integrated sites. An example of this is our current investment programme in olefins and derivative products at Grangemouth and Hull in the UK. Increasing competitive pressures in the industry require an enduring focus on cost reduction and we have made cost management an ongoing part of our business. For example, in 1999 we launched our advanced manufacturing technology project, which is intended to extensively automate most of our sites. Initial projects are at our Texas City, Texas and Decatur, Alabama sites in the US, and at Hull in the UK. We manage costs structurally too, by focusing our investment on a limited number of world-class manufacturing sites. By limiting the number of sites, we benefit from increased scale and integration of chemical operations along value chains. 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 Amoco has a number of leading technologies in operation already and is currently investing in production capacity utilizing recent breakthroughs in butanediol, vinyl acetate monomer and ethyl acetate manufacture. 29
Our leading market positions make us supplier of choice and give us access to a wider range of high quality growth options. We strive to be number one or two in the markets in which we compete, and we have global leadership in paraxylene, PTA, acetic acid, acrylonitrile, and other products. Our growth will be driven by biasing our portfolio towards products which are growing at a higher rate than the industry average. We are present in markets whose volumes are on average increasing at 6% a year overall. This is about twice the rate of global economic growth and compares with an estimated average of 4% for the petrochemicals industry. We have also instituted a programme of marketing initiatives to improve our commercial capability. The programme embraces developments in the sphere of e-commerce, including the introduction of web-based marketing channels. We will continue to focus our portfolio in areas where we have clear competitive advantage driven by the strategy elements described above. Over the course of 1999, we sold two speciality businesses, Verdugt in February and Plaskon in September; our share in the Wilton olefins cracker in June; and our Fibers and Yarns business in November. We also announced the closure of our joint-venture Singapore aromatics complex. In 2000, BP Amoco refinanced the entity's bank loans and sold its interest in the entity. MANUFACTURING FACILITIES BP Amoco has large-scale manufacturing facilities in Europe and the USA. The Group's major sites, with our share of their capacities in thousands of tonnes per annum (ktepa), are: Grangemouth (2,126 ktepa) and Hull (1,400 ktepa) in the UK; Lavera (1,817 ktepa) in France; Marl (623 ktepa) and Dormagen (2,200 ktepa) in Germany; Geel (1,504 ktepa) in Belgium; and Texas City, Texas (2,986 ktepa), Chocolate Bayou, Texas (3,220 ktepa), Decatur, Alabama (2,220 ktepa), and Cooper River, South Carolina (1,310 ktepa) in the USA. BP Amoco's European and US manufacturing base is a key to its continued success. We also aim to grow in the Asia-Pacific region, which offers prospects for demand growth. The intention is to build upon the existing bridgeheads that the Group now holds in Indonesia, China, Malaysia and Korea. Our share of capacity in Asia (largely through joint ventures) amounts to some 2.7 million tonnes as follows: Indonesia (440 ktepa), Korea (630 ktepa), Malaysia (840 ktepa), Taiwan (740 ktepa) and China (75 ktepa). The following table shows BP Amoco's production capacity by major product and by business at December 31, 1999. <TABLE> <CAPTION> Chemical Performance Feedstocks Intermediates Polymers Products Total(a) ---------- ------------- -------- ----------- ----- (thousand tonnes per annum) <S> <C> <C> <C> <C> <C> Purified teraphthalic acid (PTA) 5,357 5,357 Ethylene..................... 3,139 3,139 Paraxylene................... 2,447 2,447 Polypropylene................ 1,919 1,919 Styrenics.................... 1,458 1,458 Polyethylene................. 1,477 1,477 Acetic acid/anhydride........ 1,363 1,363 Linear/poly alpha olefins.... 830 830 Acrylonitrile................ 801 801 Other........................ 2,474 632 677 3,664 7,447 ------ ------ ------ ------ ------ Total 8,060 6,790 5,531 5,857 26,238 ====== ====== ====== ====== ====== </TABLE> - ------------ (a) This includes the Group's proportionate interest through associated undertakings in production capacity and production from third-party facilities made available to BP Amoco under long-term agreements. BP Amoco'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. 30
BP Amoco's Chemicals business is organized into four broad groupings: -- FEEDSTOCKS, including olefins and aromatics; -- CHEMICAL INTERMEDIATES, including PTA and nitriles; -- POLYMERS, including polypropylene, polyethylene, and styrenics; and -- PERFORMANCE PRODUCTS, including acetyls, linear alpha olefins, plastic fabrications, solvents, and fabrics. FEEDSTOCKS PRODUCTS Our feedstocks group produces and markets the basic petrochemical building blocks that are used primarily as raw material for other chemical products. These basic petrochemicals include ethylene, propylene, butadiene, paraxylene and metaxylene. BP Amoco manufactures and markets feedstock chemicals 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 Amoco 50%); Dormagen, Germany by Erdoelchemie (BP Amoco 50%); Chocolate Bayou, Texas; and Kertih, Malaysia (BP Amoco 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 Amoco plants. BP Amoco is the world's largest producer of paraxylene (PX), and one of the world's largest producers of metaxylene (MX), the feedstocks for PTA and purified isophthalic acid (PIA), respectively. We recover PX and MX from reformed gasoline streams at BP Amoco and other refineries, and deliver them into our aromatic acids plants. PX is produced at Texas City, Texas and Decatur, Alabama in the USA. MX is produced at Texas City. MAJOR ACTIVITIES -- Advanced Manufacturing technology projects were started at Texas City, Decatur and Hull towards the end of 1999. These initial projects are the beginning of a broader plan to implement the 'next generation' of manufacturing across the chemicals business. This will involve the introduction of leading edge process technology and control systems, and will create extensively automated facilities which are integrated with supply from the nearby refineries and demand from the downstream products. -- In the UK, work is continuing on a major $825-million development programme. Included in this programme are investments at Grangemouth. The first stage, a 50-ktepa expansion of ethylene capacity, was commissioned in March, 1999. A second 270-ktepa expansion is underway with completion scheduled for the first quarter of 2001. When the second expansion is complete, Grangemouth will have 1 million tonnes of ethylene capacity. This additional production is intended to feed a new polyethylene plant currently being built at the site. -- In Belgium, work proceeded on the construction of a 420 ktepa PX unit at our Geel site. This unit will employ our technology for PX crystallization and will incorporate new process and catalyst technologies commercialized at Decatur in 1997. The project is scheduled for start-up in early 2000. -- BP Amoco continued feasibility studies on a $2.5-billion project for an integrated ethylene cracker complex in China with the Shanghai Petrochemical Company. In October 1999, the Chinese government approved our proposal for a 50:50 joint venture, and the plant start-up is scheduled for early 2005. -- In June 1999, BP Amoco sold its 20% share of the Wilton olefins cracker. -- In December 1999, we announced the closure of our joint-venture Singapore aromatics complex. In 2000, BP Amoco refinanced the entity's bank loans and sold its interest in the entity. 31
CHEMICAL INTERMEDIATES PRODUCTS The Chemical Intermediates group produces and markets PTA, which is the preferred raw material for the manufacture of polyester; acrylonitrile, a raw material for acrylic fibre, varieties of synthetic rubber, a range of plastics and other chemical products; PIA used for isopolyester resins and gel coats; napthalene dicarboxylate (NDC), used for photographic film and specialized packaging; trimellitic anhydride (TMA), used by the automotive, construction, consumer goods, and packaging industries; and maleic anhydride (MAN), used in a wide range of plastics and resins. BP Amoco is the world's largest producer of PTA, with an interest in approximately 25% 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 Amoco 35%), Taiwan (BP Amoco 50%), Brazil (BP Amoco 49%), Mexico (BP Amoco 8.55%) and Indonesia (BP Amoco 50%). The Taiwan joint venture operation, Cooper River, and Decatur represent the three largest PTA production sites in the world. BP Amoco is also the world's largest producer and global 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 Erdoelchemie at Dormagen, Germany and through a capacity rights agreement with Sterling Chemicals at Texas City, Texas. Additionally, BP Amoco 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. We are entering the global market for 1,4-butanediol (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. PIA is produced in Joliet, Illinois; Geel, Belgium; and by the AGIC joint venture (BP Amoco 50%) in Japan. NDC is produced at our plant in Decatur, Alabama. MAJOR ACTIVITIES -- A 500 ktepa PTA unit at Geel, Belgium site was recommissioned as scheduled during the second quarter of 1999 after a fire forced us to shut it down in 1998. -- Construction progressed on a $10 million demonstration unit for our proprietary propane-to-acrylonitrile technology process at the Green Lake manufacturing facility. The project, involving an innovative recovery and purification unit of unique design which will be integrated with one of the three fluid-bed reactors at the Green Lake plant, is scheduled for completion in the summer of 2000. -- In September 1999, we commissioned an acetonitrile purification unit (APU) at the BASF acrylonitrile plant at Seal Sands, UK, providing BP Amoco with acetonitrile for sale into Europe. Owned by BP Amoco, the APU is operated by BASF. -- In June 1999, we commenced operation of a new leased import/export terminal at Point Comfort, Texas and a pipeline between Point Comfort and Green Lake for distribution and storage of acrylonitrile and raw material ammonia. -- In December 1999 we completed a 20% expansion of the TMA plant at Joliet. POLYMERS PRODUCTS The polymers product line includes polypropylene, used for moulded products, fibres and films; polyethylene, used for packaging, pipes and containers; engineering polymers used for medical, automotive and electronic applications; carbon fibres used in aerospace applications and sporting goods; and styrene monomers and polymers used in packaging and containers. 32
We are the third-largest producer of polypropylene in the world. Polypropylene is manufactured at Chocolate Bayou and Cedar Bayou, Texas and Geel, Belgium. In addition, Appryl (BP Amoco 49%) operates polypropylene plants at Lavera and at Gonfreville, France. BP Amoco 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 Amoco operates linear low density polyethylene (LLDPE) and high density polyethylene (HDPE) plants at Grangemouth, Lavera, Merak in Indonesia (BP Amoco 51%) and at Kertih in Malaysia (BP Amoco 60%). A low density polyethylene (LDPE) plant is operated at Wilton, UK. Erdoelchemie (BP Amoco 50%) also produces LLDPE and LDPE at Dormagen in Germany. Innovene, our proprietary gas-phase production process for polyethylene based on a clean and cost-effective technology, has been licensed to 25 different companies in 16 countries. We have launched an enhanced version of our High Productivity technology and have a range of next generation catalyst programmes. During 1999, we successfully produced LLDPE film using metallocene catalysts, in collaboration with Dow Chemical Company. We operate styrene monomer plants at Texas City, Texas in the USA and Marl in Germany. Polystyrene plants are operated at Marl, Wingles in France and Trelleborg in Sweden. Expanded polystyrene (EPS) plants are operated at Wingles and Marl. BP Amoco's Engineering Polymers and Carbon Fibers business has manufacturing facilities at Marietta, Ohio; Greenville and Rock Hill, South Carolina; and Atlanta and Augusta, Georgia in the USA. MAJOR ACTIVITIES -- As part of the Grangemouth expansion programme, a new 300 ktepa polyethylene plant employing enhanced High Productivity process technology is planned to be commissioned in the summer of 2000. -- Also at Grangemouth in 1999, Appryl (BP Amoco 49%) continued the construction of a 250-ktepa polypropylene plant, with commissioning expected in 2000. -- The construction of the 250-ktepa polyethylene plant for the Bataan Polyethylene Corporation (BP Amoco 38%) in the Philippines is nearing completion and is due on stream in the third quarter of 2000. -- In February 1999, new polypropylene capacity of 250 ktepa was brought on stream at the Chocolate Bayou plant in Texas. -- In the third quarter of 1999, a new polystyrene line using BP Amoco technology was successfully commissioned at Wingles. Concurrently, our styrenics business undertook a major restructuring programme, closing three older EPS units and mothballing a polystyrene train. -- In September 1999, the Plaskon business, which manufactures computer chip packaging encapsulant resins, with manufacturing facilities located in Singapore, was sold. -- The Baglan Bay, UK, styrene monomer plant was closed in November 1999. PERFORMANCE PRODUCTS PRODUCTS This group of businesses covers the following: acetic acid/anhydride, solvents, linear alpha olefins, industrial products, polybutenes, plastic fabrications group, and fabrics and fibres. These businesses add value to raw materials produced by our other chemicals businesses. 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 Amoco has acetyls operations in Europe, the USA and Korea (BP Amoco 51%), and commissioned a 150-ktepa acetic acid plant in Sichuan, China with local partners (BP Amoco 51%) in late 1998. This plant performed above capacity during 1999, and a re-rating of the capacity to 200 ktepa was announced in October 1999. In Korea, the Asian Acetyls Company (BP Amoco 34%) operates a 150 ktepa vinyl acetate monomer (VAM) plant. BP Amoco 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. 33
BP Amoco is the world's leading merchant supplier of polybutene. Polybutene is manufactured at Texas City, Texas, and Whiting, Indiana in the US, and at Lavera, France. Our Grangemouth polybutene facility was closed in 1999 as part of an asset optimization drive. Polybutene is consumed as 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 as co-monomers in the production of polyethylene, as intermediates for the manufacture of linear plasticizers for polyvinyl chloride (PVC), as raw material to manufacture poly alpha olefins (PAO) for synthetic lubricants, as a building block 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. LAOs are produced at our facilities in Pasadena, Texas and Feluy, Belgium. To meet the requirements of the industry, production of LAOs at our plant in Feluy was increased during the second quarter of 1999 by 50%. This increase in production pushed capacity to 300 ktepa. BP Amoco is the world's leading merchant supplier of poly alpha olefins (PAO), high viscosity index materials primarily used in the production of high performance, environmentally friendly, synthetic lubricants and motor oils. These materials are manufactured at facilities in Deer Park, Texas and Feluy. Our other Performance Product businesses are: (i) Solvents and Industrial Chemicals, which manufactures and markets acetate esters, iso-propanol, acetone, glycol esters, aerosols and ethanol at plants in the UK, France, Belgium, Italy and Korea. These products have many applications including pharmaceuticals, inks and paints. This business also manufactures ethylene oxide, ethanolamines, brake fluids, antifreeze, oilfield chemicals, and plasticizers; (ii) Plastic Fabrications, with a number of European and US sites converting polymer resins into plastic films, rigid containers, non-woven fibres and engineering components; and (iii) Fabrics and Fibers, which makes products for carpet backing and industrial uses such as civil engineering fabrics and bulk bags. MAJOR ACTIVITIES -- Construction began on a 220-ktepa ethyl acetate plant at Hull and 110 ktepa ethanol plant at Grangemouth, both scheduled for completion in 2001. The ethyl acetate investment is based on BP Amoco's innovative proprietary 'direct addition' method for making ethyl acetate from ethylene and acetic acid which does not require ethanol as a raw material. -- Construction continues on a 200-ktepa VAM plant at Hull, which uses the proprietary BP Amoco LEAP technology based on fluid bed catalyst. The work is scheduled for completion in 2001, and the plant will ultimately replace production from Baglan Bay and Porto Marghera. -- We are investing with Petroliam Nasional Berhad (Petronas) in an acetic acid plant at Kertih, Malaysia, with a capacity of 400 ktepa (BP Amoco 70%). Construction of the plant, which will use our Cativa technology, started in 1998, and production is scheduled to commence during 2000. -- In 1999 we commenced construction of a $300-million, 250-ktepa LAO facility in Alberta, Canada. It is scheduled to come online in 2001. The facility is based on technology used in our Feluy plant. -- In February 1999, we sold a small speciality business, Verdugt, in the Netherlands and in October we disposed of Plaspack Kunststoffe, a plastic net and webbing business in Austria. In November, we sold our Fibers and Yarns business, located in the US. OTHER BUSINESSES AND CORPORATE Other Businesses and Corporate comprises Finance, BP Solarex, the Group's remaining coal asset, interest income and costs relating to corporate activities worldwide. 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 Amoco and the international financial markets, and makes available a range of financial services to the Group including supporting the financing of BP Amoco'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 Amoco. 34
Finance has in place a Debt Issuance Programme, under which the Group may raise an aggregate of $4 billion of debt for maturities of one month or longer. At March 24, 2000 the amount drawn down against this programme was $2,705 million. In 1999, BP Amoco purchased the 50% of Solarex it did not already own from Enron Corporation for $45 million. Our expanded SOLAR business was renamed BP Solarex. The new company has a 20% share of the global market and is one of the largest manufacturers of photovoltaic cells and modules with plants in the USA, Spain, Australia and India. In 1999 BP Solarex revenues totalled $179 million and solar module production grew 23%. Many of BP Solarex's successes in 1999 were based on advanced technology. One major project, 'Plug in the Sun', involved installing solar modules on 200 new BP Amoco service stations in nine countries. Another involved using solar energy to power 665 houses in the Athlete's Village adjacent to the Olympic site in Sydney, Australia. 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. 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 Amoco 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 Amoco'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 economic for the Group. Losses will therefore be borne as they arise, rather than being spread over time through insurance premia. The position is reviewed periodically. 35
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 close to a shipping lane. The UK Health and Safety Executive has wide powers and duties in relation to offshore health and safety. BP Amoco 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. 36
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 L10 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. In his Budget of July 1997 the UK Chancellor announced a review of the North Sea fiscal regime to ensure that an appropriate share of North Sea profits is being taxed while continuing to maintain a high level of oil industry interest in the future development of the UK's oil and gas reserves. In BP Amoco's submission to the review it argued that the existing fiscal regime broadly succeeds in both areas. In September 1998 the Chancellor announced that the existing regime would not be changed. 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 (the 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. 37
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 other activities. These laws and regulations may require the Group to take future action 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, 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 Amoco'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. 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 liabilities is inherent in particular operations and products of the Group and there can be no assurance that material costs and liabilities 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 9 -- Management's Discussion and Analysis of Financial Condition and Results of Operations -- Environmental Investment. 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. Projections of the increase in emissions without any reduction measures are estimated at 32% for the USA and 19% for the European Union. 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 Amoco's main businesses, but the Group does not expect that it will be affected differently from other companies with comparable assets engaged in similar businesses. The following is a summary of significant health, safety and environmental legislation affecting the Group in 1999. UNITED STATES The Clean Air Act and its regulations require, among other things, enhanced monitoring of major sources of specified pollutants, stringent 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. 38
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 Amoco 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 Amoco 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. Some metropolitan areas have been able to achieve compliance with carbon monoxide standards and terminate their oxygenated fuels programmes. Beginning 1993, the Clean Air Act limited highway diesel fuel sulphur content to 0.05%. BP Amoco 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. 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 US Environmental Protection Agency (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 2000 with compliance required in 2003. The EPA is also attempting to impose more stringent controls on the emission of nitrous oxides (NOx) and particulate matter. 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. 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. During 1998, individual states in the Great Lakes watershed were working on regulations implementing the federal rule. The Oil Pollution Act of 1990 (the Oil Pollution Act) significantly increased oil spill prevention requirements, spill response planning obligations and spill liability for vessels, offshore facilities (such as platforms) and onshore terminals. To provide compensation for oil spill response where the spiller is unable to do so, the Oil Pollution Act created a $1 billion fund, funded by a tax on imported and domestic oil. The Oil Pollution Act also requires double hulls on all new tankers operating in US waters and double hulls installed on existing tankers on a phased schedule between the years 1995 and 2015. Major oil shippers and handling facilities are expected to be most affected by the expanded technical and operational requirements for tankers under the Oil Pollution Act. Regulations require businesses covered by this Act to carry specified levels of insurance or other documentation of financial responsibility and maintain facility response plans that, among other things, identify and prepare for worst case spill scenarios. Facilities must also conduct emergency response programmes in coordination with area and national response 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. 39
BP Amoco has set performance objectives to enhance emergency preparedness and crisis management at all facilities, and to promote compliance with all related legislation 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. 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 where such wastes have been previously handled or disposed of. RCRA requirements have become increasingly stringent in recent years. BP Amoco facilities generate a number of wastes regulated by RCRA and have units that have been used for the storage, handling or disposal of RCRA wastes. 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 liable for the entire cost of addressing sites contaminated by spills or waste disposal regardless of fault or the amount of waste contributed to a site. Additionally, most states have laws similar to CERCLA. BP Amoco has been identified as a Potentially Responsible Party (PRP) under CERCLA and similar state statutes at approximately 420 sites. A PRP has a joint and several liability for site remediation costs and so BP Amoco may be required to assume, among other costs, the share attributed to insolvent, unidentified or other parties. BP Amoco is the PRP identified as having the most significant exposure for remediation costs at 27 of these sites. For the remaining sites the number of PRPs ranges generally from 20 to 200, and BP Amoco expects its share of remediation costs in respect of these sites to be small. BP Amoco has estimated its potential exposure at all sites where it has been identified as a PRP and has accrued provisions accordingly. BP Amoco does not anticipate that its ultimate liability at these sites individually, or in aggregate, will be significant. The Group is also subject to claims made for natural resource damage under several federal and state laws. 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 (PSM) rule formalizes the procedures used in identifying and minimizing safety risks at a covered facility and also in conducting formal documented hazard reviews of all covered processes. 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 Amoco 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 Amoco 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 Amoco 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. A European Commission directive for a similar system of Integrated Pollution Prevention and Control (IPPC) is based upon Best Available Techniques (BAT) with 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 meeting 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. 40
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 2001, 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 10 ppm 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 Commission Directives, two more have been proposed 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. 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 (VOC). 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 ppm, 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. 41
The European Union enacted the Major Hazards (Seveso) Directive (the Seveso 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 Amoco sites in Europe are in compliance with the Seveso Directive as enacted in each specific country. The European Union has now adopted a revised Seveso 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. The European Commission is committed to issue in early 2000 a `white (consultation) paper' on the scope for proposing 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 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 Amoco 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 Amoco 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. MANAGEMENT OF HEALTH, SAFETY AND ENVIRONMENTAL ISSUES The Group's world-wide HSE policy is developed within a framework set by BP Amoco p.l.c.'s board of directors. The policy is implemented through targets in the corporate and business performance contracts and programmes ranging from pollution prevention through safety management and product stewardship. Each part of the BP Amoco Group reviews its own performance and an assurance report is presented annually to the Group Chief Executive. The Ethics and Environment Assurance Committee of the board of directors, comprising six non-executive directors, reviews policies and processes which bear upon the Group's health, safety and environmental relationships. ADDITIONAL FACTORS WHICH MAY AFFECT BUSINESS In order to utilize the `Safe Harbor' provisions of the United States Private Securities Litigation Reform Act of 1995, BP Amoco 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 Amoco and certain of the plans and objectives of BP Amoco 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 1 - Description of Business and Item 9 - Management's Discussion and Analysis of Financial Condition and Results of Operations 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, and statements regarding the benefits of the merger with ARCO; and (ii) the statements in Item 9 - Management's Discussion and Analysis of Financial Condition and Results of Operations including the statements under `Outlook' with regard to trends in results of operations, margins overall market trends, costs, dividends, returns, risk management and exchange rates, are 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 Amoco. 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 following 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. 42
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 also 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. The refining industry is suffering from severe oversupply. 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. ITEM 2 -- DESCRIPTION OF PROPERTY BP Amoco 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 1 -- Description of Business for a description of the Group's reserves and sources of crude oil and natural gas. 43
ITEM 3 -- LEGAL PROCEEDINGS Save as disclosed in the following paragraph, 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 Amoco owns a 50% interest in Alyeska through a subsidiary of BP America Inc. 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 Amoco would defend the claims vigorously. 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 Amoco 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 Amoco'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 February 1998, a jury in a Texas state court awarded compensatory and punitive damages in the aggregate amount of $115 million to former employees of a steel company. The plaintiffs had alleged that they suffered injuries following their use of products containing asbestos, sold during 1965 to 1983 by Carborundum, a former subsidiary of BP America Inc. These proceedings have now been settled between the parties on the basis of an annulment of the court judgement. Other such claims will be defended vigorously. In February 2000, the FTC filed a Complaint in the US District Court against BP Amoco and ARCO, seeking a preliminary injunction to prevent closing of the combination transaction between BP Amoco and ARCO. The Attorney Generals for the Western States also filed complaints with the same Court. The Attorney General for the State of Alaska also joined in the Court proceedings in support of the transaction. The parties agreed on March 15, 2000, to suspend the Court proceedings, pending discussions for a consent order. In March 2000, ExxonMobil filed a Complaint in State Court, Los Angeles, seeking declaratory and injunctive relief and specific performance against BP Amoco, ARCO and Phillips to prevent the sale of ARCO's Alaskan business to Phillips referred to in Part 1 -- Recent Developments -- The Proposed Combination of BP Amoco and ARCO. 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. BP Amoco believes that this action is without merit and will defend the claim vigorously. ITEM 4 -- CONTROL OF REGISTRANT The following table sets forth certain shareholding information as of March 24, 2000, concerning the directors and the secretary of BP Amoco p.l.c. <TABLE> <CAPTION> Title of class Identity of person or group Number owned Percent of class - -------------- --------------------------- ------------ ---------------- <S> <C> <C> <C> Ordinary Shares of Directors and the 25 cents each secretary of BP Amoco p.l.c. 5,478,669(a) less than 1/10th of 1% </TABLE> - ---------- (a) Includes the equivalent of 2,304,959 Ordinary Shares held by certain directors and the secretary in the form of ADSs. There are no interests of more than 10% of the Company's Ordinary Shares, other than Morgan Guaranty Trust Company of New York as Depositary for Ordinary Shares underlying ADSs. See Item 5 -- Nature of Trading Market. 44
ITEM 5 -- NATURE OF TRADING MARKET 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 Amoco'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. Each ADS represents six Ordinary Shares. ADSs are listed on the New York Stock Exchange, and are also traded on the Chicago, Pacific and Toronto Stock Exchanges. The Ordinary Shares represented by ADSs issued pursuant to the merger between BP and Amoco were issued in bearer form at the time of the merger. As at March 24, 2000, 5,411,636,254 Ordinary Shares in bearer form are held by the Depositary in London, with 32,507,346 Ordinary Shares being held by Boston Equiserve Limited, as exchange agent on behalf of Amoco shareholders that have yet to exchange their Amoco shares for BP Amoco ADSs. With effect from 4 October 1999, BP Amoco subdivided (or split) its ordinary share capital. As a result, the number of ordinary shares held at the close of business on Friday October 1, 1999 doubled. This resulted in holders of ADSs receiving a two-for-one stock split. Therefore, for every ADS held before the stock split, a holder received an additional ADS. The following table sets forth for the periods indicated the highest and lowest middle market quotations for the Ordinary Shares of The British Petroleum Company p.l.c. for 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 restated to reflect the subdivision of Ordinary Shares on October 4, 1999. <TABLE> <CAPTION> American Depositary Ordinary Shares Shares (a) --------------- --------------- High Low High Low ---- --- ---- --- (Pence) (Dollars) <S> <C> <C> <C> <C> 1998: First quarter....................... 466.75 373.00 48.00 36.88 Second quarter...................... 484.25 415.50 48.66 41.44 Third quarter....................... 455.00 368.50 45.88 36.50 Fourth quarter...................... 478.25 407.50 47.69 40.72 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 (through March 24).... 602.00 444.50 60.63 43.13 </TABLE> - ---------- (a) An ADS is equivalent to six Ordinary Shares. Market prices for the 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. 45
On March 24, 2000, 921,098,875 ADSs (equivalent to 5,526,593,250 Ordinary Shares or some 28.4% of the total) were outstanding and were held by approximately 121,000 ADR holders. Of these, about 119,000 had registered addresses in the USA at that date. On March 24, 2000 there were approximately 372,000 holders of record of Ordinary Shares. Of these holders, around 1,200 had registered addresses in the United States and held a total of some 3,662,000 Ordinary Shares. In addition, certain accounts of record with registered addresses other than in the United States hold Ordinary Shares, in whole or in part, beneficially for United States persons. ITEM 6-- EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS There are currently no UK foreign exchange controls or restrictions on remittances of dividends on the 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 Ordinary or Preference Shares in the Company. ITEM 7 -- TAXATION The following summary of the principal UK and certain US tax consequences of ownership of ADSs or 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 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 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. UK TAXATION OF DIVIDENDS POSITION FOR DIVIDENDS PAID BEFORE APRIL 6, 1999 BP Amoco p.l.c. was required, when paying a cash dividend, to account to the UK Inland Revenue for a payment of advance corporation tax (ACT). The rate of ACT was 1/4 of the net dividend (equivalent to 20% of the combined dividend and ACT). Under UK law, an individual shareholder resident in the UK for UK income tax purposes is treated as having taxable income equal to the sum of any dividend paid plus a tax credit equal (before April 6, 1999) to 1/4 of the amount of the net dividend. The tax credit was available to be set against the individual's tax liability on the dividend, and might in appropriate cases be refunded. A UK resident corporate shareholder will not generally be liable to UK corporation tax on any dividend received. Under the Convention, 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 (a US Holder) and whose holding of the Company's shares is not effectively connected with (i) a permanent establishment in the UK through which the US Holder carries on a business in the UK, or (ii) a fixed base from which the US Holder performs independent personal services in the UK, will generally be entitled to receive from the UK Inland Revenue, in addition to any dividend paid by the Company, 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 (the Refund). For example, a dividend of $8.00 would entitle such a US Holder to receive a Refund of $0.50 (a tax credit of $2.00, less a withholding of $1.50), giving a total net receipt, after UK taxes but before US taxes, of $8.50. 46
Special rules may apply under certain circumstances if the US Holder (a) is exempt from tax in the USA on dividends paid by the Company, or (b) is an investment or holding company, 25% of the capital of which is held directly or indirectly by one or more persons who are not individual residents or nationals of the USA and (i) which has imposed on it by the USA, in respect of the dividend, a tax substantially less than the tax generally imposed by the USA on corporate profits, or (ii) which receives more than 80% of its gross income from sources outside the USA as determined in accordance with the Convention. Special rules apply to a US Holder who owns 10% or more of the Ordinary Shares and to US corporate shareholders which directly or indirectly control, alone or with one or more associated corporations, at least 10% of the voting power of the Company or are residents of the UK. Arrangements existed with the UK Inland Revenue under which a holder of ADRs resident in the USA that was (i) a US corporation whose business was not managed and controlled in the UK, (ii) an individual resident in the USA and not resident in the UK, or (iii) a trust or estate, all the beneficiaries of which were resident in the USA, would receive payment of the Refund to which such holder was entitled, together with payment of the associated cash dividend, provided that the holder was not subject to the special rules described in the preceding paragraph, completed the declaration on the reverse of the dividend check and presented the check for payment within three months from its date of issue. The holder had to declare, among other things, that he was neither engaged in business nor performing independent personal services through a permanent establishment or fixed base in the UK. These arrangements were terminated by the UK Inland Revenue with effect from April 6, 1999. A US Holder who did not receive the Refund to which such US Holder is entitled must, in order to obtain payment, file in the manner and at the time described in Revenue Procedure 80-18, 1980-1 C.B. 623 (as modified by Revenue Procedure 81-58, 1981-2 C.B. 678 and Revenue Procedure 84-60, 1984-2 C.B. 504, clarified and amplified by Revenue Procedure 90-61, 1990-2 C.B. 657 and as recently modified by Revenue Procedure 2000-13, 2000-6 I.R.B. 515), a claim for payment identifying the dividends with respect to which the ACT was paid. The first claim by such a US Holder for a payment is made by sending the appropriate UK tax form in duplicate to Philadelphia Service Center, Foreign Certification Unit, P.O. Box 16347, DP535B, Philadelphia, PA19114. Forms may be obtained from the IRS Assistant Commissioner (International), 950 L'Enfant Plaza South, S.W., Washington, D.C. 20024. If the US Holder qualifies as a US resident, the Internal Revenue Service (IRS) will certify the form to that effect and forward it to the UK tax authorities. Claims must be made within six years of the end of the UK year of assessment (generally the 12-month period ending April 5 in each year) in which the related dividend was paid. As a claim is not considered made until the UK tax authorities receive the appropriate form from the IRS, forms should be sent to the IRS well before the end of the applicable limitation period. Any Refund claim by a US Holder after the first claim should be filed directly with the Financial Intermediaries and Claims Office (International), FitzRoy House, PO Box 46, Nottingham, NG2 1BD, England. Whether shareholders who reside in countries other than the USA are entitled to the tax credit in respect of dividends on such shares depends in general upon the provisions of such conventions or agreements as may exist between such countries and the UK. In addition to that with the USA, conventions or agreements presently exist between the UK and, among other countries, Australia, Austria, Belgium, Canada, Denmark, Finland, France, Germany, Greece, Ireland, Italy, Japan, Luxembourg, the Netherlands, New Zealand, Norway, Portugal, Singapore, Spain, Sweden and Switzerland. POSITION FOR DIVIDENDS PAID ON OR AFTER APRIL 6, 1999 The Finance (No 2) Act 1997 introduced new legislation which significantly altered the tax treatment of dividends paid on or after April 6, 1999. As from that date the tax credit for an individual shareholder resident in the UK is reduced to 1/9 (or 10% of the net dividend plus the tax credit) of the amount of the net dividend. 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 a US Holder as defined above this amendment has the effect of reducing the Refund available under the Convention to nil, since the amount of the withholding tax (at 15%) exceeds the 10% tax credit available to individual shareholders resident in the UK. Following the example given above, a dividend of $8.00 will result in a net receipt after UK tax but before US tax of $8.00, rather than $8.50 (the withholding tax does not reduce the dividend below the net dividend of $8.00). The Finance Act 1998 also abolished the requirement for UK companies to pay ACT on cash dividends as from April 1, 1999. This does not affect the tax treatment of dividends described above. 47
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 Federal income tax purposes. Such dividends will generally not be eligible for the dividends received deduction allowed to US corporations. The IRS has recently confirmed, in Revenue Procedure 2000-13, 2000-6 I.R.B. 515, that, in the case of qualifying 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, US holders must make an election on Form 8833 (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 AMOCO ADR HOLDERS ADR holders electing to receive ADSs instead of a cash dividend (see Item 8 - -- Selected Financial Data -- 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. FOREIGN INCOME DIVIDENDS The Finance Act 1994 introduced new legislation under which companies were able on or after July 1, 1994 to elect to pay a 'foreign income dividend' with special tax treatment. ACT would be payable by the Company on such a dividend, but surplus ACT not creditable against mainstream corporation tax liabilities may be repayable to the Company later, based on the extent to which the dividend was shown to have been paid out of sufficiently taxed foreign source profits. Shareholders would obtain no tax credit. However, they would be treated for UK tax purposes as having received income which had suffered tax at 20%. No Refund would be available to US Holders in respect of any such dividends. BP Amoco did not elect to pay a foreign income dividend. The Finance (No. 2) Act 1997 repealed the foreign income dividend legislation with effect from April 6, 1999. 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 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 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 US holders of ADRs is the same as that for a US holder of 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. 48
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 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 Ordinary Shares even if the agreement is made outside the UK between two non-residents. Purchases of Ordinary Shares outside the CREST system are subject either to stamp duty at a rate of 50 pence per L100 (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 Ordinary Shares to the Depositary's nominee will give rise to further stamp duty at the rate of L1.50 per L100 (or part) or stamp duty reserve tax at the rate of 1.5% of the value of the Ordinary Shares at the time of the transfer. A transfer of the underlying 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 50 pence per transfer (which is increased to L5 in the 1999 UK budget). 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. 49
ITEM 8 -- SELECTED FINANCIAL DATA SUMMARIZED FINANCIAL INFORMATION The information shown below for 1999, 1998 and 1997 has been extracted or derived from the audited financial statements of the BP Amoco Group presented elsewhere herein. The information for 1996 and 1995 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 restated to conform with the accounting presentation adopted in this annual report. <TABLE> <CAPTION> Years ended December 31, ----------------------------------------------- 1999 1998 1997 1996 1995 ----- ----- ----- ----- ----- ($ million except per share amounts) -------------------------------- UK GAAP INCOME STATEMENT DATA <S> <C> <C> <C> <C> <C> Turnover.............................. 101,180 83,732 108,564 102,064 84,216 Less:joint ventures................... (17,614) (15,428) (16,804) -- -- ----- ----- ----- ----- ----- Group turnover........................ 83,566 68,304 91,760 102,064 84,216 Total replacement cost operating profit(a) 8,894 6,521 10,683 10,634 8,264 Replacement cost profit before exceptional items (b)............. 5,330 3,959 6,622 6,659 4,943 Profit for the year................... 5,008 3,220 5,673 7,417 3,700 Per Ordinary Share (c): (cents) Profit for the year: Basic............................... 25.82 16.77 29.56 38.79 19.52 Diluted............................. 25.68 16.70 29.41 38.63 19.45 Dividends (d)....................... 20.0 19.8 18.0 15.5 13.5 BALANCE SHEET DATA Total assets.......................... 89,561 84,915 86,279 88,651 81,499 BP Amoco Shareholders' interest....... 43,281 42,501 42,503 42,130 36,789 Finance debt due after more than one year 9,644 9,641 8,853 8,954 10,257 Debt to borrowed and invested capital (e) 18% 18% 17% 17% 22% OTHER DATA Per Ordinary Share: (cents) Replacement cost profit before exceptional items................. 27.48 20.62 34.51 34.82 26.09 Net cash inflow from operating activities(f)....................... 10,290 9,586 15,558 13,679 12,682 Net cash outflow from capital expenditure acquisitions and disposals............. 5,142 6,520 10,056 8,056 7,183 US GAAP INCOME STATEMENT DATA Revenues.............................. 83,566 68,304 91,760 102,064 84,216 Profit for the period................. 4,596 2,826 5,686 6,795 3,991 Comprehensive income.................. 3,674 2,848 4,106 7,218 4,346 Profit per Ordinary Share(c)(g):(cents) Basic............................. 23.70 14.72 29.62 35.54 21.05 Diluted........................... 23.56 14.66 29.46 35.39 20.98 Profit per American Depositary Share(c)(g)(h):(cents) Basic............................. 142.20 88.32 177.72 213.24 126.30 Diluted........................... 141.36 87.96 176.76 212.34 125.88 BALANCE SHEET DATA Total assets.......................... 90,342 85,538 87,076 89,934 89,929 BP Amoco Shareholders' interest....... 37,838 37,334 37,504 37,259 32,475 OTHER DATA Net cash used in investing activities. 4,922 6,861 10,151 8,311 7,160 Net cash used in financing activities. 3,332 2,161 3,449 3,239 3,723 </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. 50
BP Amoco 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 Amoco 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 Amoco for many years. Operating profit on the replacement cost basis is used by BP Amoco management as the primary measure of business unit trading performance and BP Amoco management believes that this measure assists investors to assess BP Amoco'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 Amoco 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 Amoco'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 Amoco'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 Amoco'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 Amoco'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 is the measure of profit used by the BP Amoco board in setting targets for and monitoring performance within BP Amoco. BP Amoco's management believes this indicator provides the most relevant and useful measure for investors because it most accurately reflects underlying trading performance. (c) With effect from October 4, 1999 BP Amoco 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 1995 to 1998 inclusive have been restated accordingly. (d) BP Amoco dividends per share represent historical dividends per share paid by BP for 1995 to 1998 inclusive. (e) Finance debt due after more than one year, compared with such debt plus BP Amoco 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 -- Note 44 of Notes to Financial Statements. (g) FASB Statement of Financial Accounting Standards No. 128-- 'Earnings per Share' (SFAS 128) was adopted for the accounting period ending December 31, 1997. Amounts for prior periods have been restated as required by SFAS 128. (h) 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 Ordinary Shares. Comparative figures for 1995 and 1996 have been restated accordingly. (i) The Group has adopted Financial Reporting Standard No.12 `Provisions, Contingent Liabilities and Contingent Assets' with effect from January 1, 1999. Comparative figures for 1995 to 1998 inclusive have been restated accordingly. 51
DIVIDENDS BP p.l.c. paid dividends on its Ordinary Shares in each year since 1917. In 1999, there was a dividend payment in February to holders of BP p.l.c. Ordinary Shares and ADSs as at November 13, 1998. There were further dividend payments in April, June, September and December to harmonize payment dates for former BP and Amoco shareholders. In 2000 and thereafter, dividends will be paid quarterly in March, June, September and December. Until their shares have been exchanged into the form of BP Amoco ADSs, Amoco Shareholders do not have the right to receive dividends. BP Amoco announces dividends on Ordinary Shares in US dollars and at the same time states an equivalent sterling dividend. Prior to the fourth quarterly dividend of 1998 BP 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 7 -- Taxation. 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. DIVIDENDS PER AMERICAN DEPOSITARY SHARE (a)(b) <TABLE> <CAPTION> Quarterly -------------------------------- First Second Third Fourth Total ------ ------ ------ ------ ------ <S> <C> <C> <C> <C> <C> 1995.......................... UK pence 11.3 15.0 15.0 15.9 57.2 US cents 18.0 24.1 23.7 24.4 90.2 Can. cents 24.4 32.6 32.0 33.5 122.5 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 </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 Ordinary Shares. Comparative figures for 1995 and 1996 have been restated accordingly. (b) With effect from October 4, 1999 BP Amoco 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 1995 to 1998 inclusive have been restated accordingly The share dividend plan whereby holders of 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 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. 52
A dividend reinvestment plan is, however, available for holders of ADSs through Morgan Guaranty Trust Company of New York. Future dividends of BP Amoco p.l.c. will be dependent upon future earnings, the financial condition of the Group, the Additional Factors which may affect the business of the Group set out in Item 1 -- Description of Business, and other factors. 53
ITEM 9 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GROUP RESULTS <TABLE> <CAPTION> Years ended December 31, -------------------------- HIGHLIGHTS 1999 1998 1997 ----- ----- ----- <S> <C> <C> <C> <C> Total replacement cost operating profit........... ($ million) 8,894 6,521 10,683 Replacement cost profit before exceptional items.. ($ million) 5,330 3,959 6,622 Replacement cost profit for the year.............. ($ million) 3,280 4,611 6,612 Historical cost profit for the year............... ($ million) 5,008 3,220 5,673 Profit per Ordinary Share (diluted)............... (cents) 25.68 16.70 29.41 Dividends per Ordinary Share...................... (cents) 20.0 19.8 18.0 </TABLE> The Group has adopted Financial Reporting Standard No.12 `Provisions, Contingent Liabilities and Contingent Assets' with effect from January 1,1999. Comparative figures for 1998 and 1997 have been restated accordingly. BP Amoco's 1999 operating performance reflected the substantial benefits of restructuring and integration following the merger, together with ongoing cost control. The trading environment was broadly neutral, with higher average oil prices substantially offset by weaker downstream and chemicals margins. European currencies were significantly weaker and sterling was marginally weaker against the US dollar in 1999. 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 and fundamental restructuring costs), BP Amoco 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, and discloses also replacement cost profit before exceptional items, after adjusting for these special items. 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. Both exceptional and special charges have been significant in 1999. The discussion below addresses each of these various measures and disclosures. 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% on an adjusted basis) 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). 54
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. During 1999, some 16,000 employees left the Group through severance or outsourcing arrangements. Of these, some 13,000 were based in the USA. The reductions arose mainly in Houston, Texas; Chicago, Illinois; and Cleveland and Warrensville, Ohio. Approximately 4,000 more employees had received notification of the termination of their employment by the end of 1999 and are expected to leave the Group in 2000. 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 Amoco merger. Following completion of the merger on December 31, 1998 and in the context of low oil prices at the time, BP Amoco 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 prices. Under this programme the Group disposed of its Canadian oil properties, its interest in the Pedernales oil field in Venezuela and certain chemicals operations. In 1998, financial performance was affected by general price deflation and erosion of margins, with a 34% fall in average oil realizations and deterioration in both the downstream and chemicals environments. Productivity improvements, cost savings and higher sales volumes partially offset this significant downturn in the operating environment. The US dollar was relatively stable against European currencies in 1998. In 1997 most currencies declined against the dollar, except for sterling which strengthened to an average of $1.64/L1 from $1.56/L1 in 1996. Replacement cost profit before exceptional items (which excludes inventory holding gains and losses) for 1998 was $3,959 million compared with $6,622 million in 1997, a fall of 40%. In addition to exceptional items these results included net special charges of $597 million ($469 million after tax) in 1998 and $133 million ($106 million after tax) in 1997. The special charges in both years consisted principally of write-downs in respect of asset impairments. After excluding these special charges, the 1998 result was 34% lower than that of 1997. The 1998 results reflected the then new requirement to capitalize certain information technology expenditure of a type which had been expensed in previous years. The amount capitalized in 1998 was some $160 million. The return on average capital employed, based on replacement cost profit before exceptional items, was 9% compared to 14% in 1997. On an adjusted basis the return on average capital employed was 10% in 1998 compared to 14% in 1997. The historical cost profit for 1998 was $3,220 million after inventory holding losses of $1,391 million. This compared with a profit of $5,673 million after inventory holding losses of $939 million for 1997. The results for 1998 included net exceptional profits of $850 million ($652 million after tax); those of 1997 included net exceptional profits of $128 million ($10 million loss after tax). 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 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. 55
The major elements of the net profit before tax on the sale of businesses and fixed assets in 1997 of $440 million were the sales of US exploration and production properties and an intrastate natural gas pipeline unit in Texas. The loss on sale of businesses by joint ventures relates principally to the costs of the BP/Mobil joint venture terminating base oil manufacturing operations at Llandarcy in the UK. Also in 1997, there was a net charge for refinery network rationalization of $47 million which represented the balance of the costs associated with the rationalization of the BP Amoco Group's international refining system announced in 1995. In addition, there were one-off costs associated with the setting-up of the European refining and marketing joint venture with Mobil amounting to $265 million. These costs represented the Group's share of charges for severance, restructuring, rebranding and other implementation charges. Capital expenditure and acquisitions in 1999 amounted to $7,345 million, 29% down on 1998, reflecting greater focus in the capital programme following the merger. Expenditure in 1999 included $400 million in respect of the Group's purchase of a significant part of Repsol YPF's share of assets in the Crescendo Resources partnership. Disposal proceeds, arising primarily from the post-merger asset divestment programme, amounted to $2,441 million. Capital expenditure net of divestments was $4,904 million (1998 $8,195 million). Within the context of the Group's targets, capital expenditure in 2000 is projected to be around $10 billion, excluding significant acquisitions, reflecting the businesses' growth agenda underpinned by continuing discipline in the capital programme. The total dividends announced for 1999 were $3,884 million, against $4,121 million for 1998. 1998 dividends included a second fourth-quarterly dividend to former Amoco shareholders to harmonize timing of quarterly dividend payments as a result of the merger. Dividends per share for 1999 were 20.0 cents ($1.20 per ADS) compared with 19.8 cents per share ($1.19 per ADS) for 1998. The Group 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 DRIP was introduced in 1999 to replace the previous share dividend plan which was terminated owing to the abolition of UK advance corporation tax. The BP Amoco Direct Access Plan for US and Canadian investors also includes a dividend reinvestment feature. The Group will seek authority from shareholders at the April 2000 annual general meeting for the repurchase and cancellation of shares up to a maximum of 1,948,600,000 Ordinary Shares (approximately 10% of the ordinary issued share capital at December 31, 1999). This will allow share buybacks as and when the Group's funding position permits. 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 $8,894 million in 1999, $6,521 million in 1998 and $10,683 million in 1997. The business results which follow are presented on this basis. EXPLORATION AND PRODUCTION <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ---- ----- ----- <S> <C> <C> <C> <C> Total replacement cost operating profit................... ($ million) 7,194 3,231 7,385 Results included: Exploration expense.................................... ($ million) 548 921 962 Key statistics: Average prices realized by BP Amoco : North Sea........ ($/bbl) 17.6 12.7 19.1 : Alaskan North Slope ($/bbl) 16.1 12.6 19.0 : US natural gas... ($/mcf) 2.1 1.8 2.2 Crude oil production (a).................................. (mb/d) 2,061 2,049 1,930 Natural gas production (a)................................ (mmcf/d) 6,067 5,808 5,858 Total production (a)(b)................................... (mboe/d) 3,107 3,050 2,940 </TABLE> - ---------- (a) Includes BP Amoco's share of associated undertakings. (b) 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. 56
The replacement cost operating profit for 1999 was $7,194, an improvement of 123% over the equivalent result of 1998. After adjusting for special charges of $299 million, the adjusted result of $7,493 million represented an increase of 102% on the adjusted result of $3,716 million for 1998. Special charges in 1998 amounted to $485 million. 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. In 1999, finding and development costs averaged $3.3 a barrel of oil equivalent, representing a substantial reduction on the $4.70 per barrel in 1998. Lifting costs averaged $2.7 a barrel of oil equivalent, compared with $3.2 in 1998. In 1998 our upstream business performed well in a most difficult environment. Replacement cost operating profit of $3,231 million, represented a decline of 56% (50% after adjusting for net special charges) compared with 1997. Brent North Sea oil averaged $6.4 a barrel below the 1997 level while North American natural gas prices were some 40 cents per thousand cubic feet below the 1997 average. The special charges of $485 million principally comprised $200 million for the write-down of the Group's investment in A O Sidanco and $104 million for the impairment of the Opon field and $110 million for the adjacent power plant in Colombia. Increased production volumes, coupled with a sustained focus on costs, boosted this performance. Production grew 3.7% to 3,050 mboe/d. Production of oil, condensate and natural gas liquid increased by 6.2% to 2,049 thousand barrels a day (mb/d) from 1,930 mb/d in 1997, while natural gas production fell 0.9% to 5,808 million standard cubic feet a day (mmcf/d) from 5,858 mmcf/d because of the decline at older UK offshore fields. The production growth in 1998 was supported by strong performance from our 1997 start-ups, and completion of a large number of new projects in 1998. These included ETAP, Viking Phoenix, Brown and Bruce Phase 2 in the North Sea; Schiehallion and Loyal, west of Shetland; Hugoton natural gas plant in the USA; the second phase of development of the Cusiana/Cupiagua project in Colombia; and Pedernales phase 2 in Venezuela. Start-up of these projects contributed towards the transfer of 1.38 billion barrels of oil equivalent of reserves to developed status. In 1999, Exploration and Production's reserves replacement exceeded production for the sixth consecutive year, with 1,172 million barrels of oil equivalent added to proved reserves. The proportion of gas in these reserve additions was similar to that of 1998 at about 66%. 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 Amoco has a 35% interest, announced that it had been awarded a deep water concession offshore Brazil, the BFZ-2 block. This will be BP Amoco's second operatorship in the area. Also in December 1999, BP Amoco and Repsol YPF dissolved their partnership, Crescendo Resources, a major gas producer and processor in Texas and Oklahoma, USA. Subsequently, BP Amoco purchased a significant part of Repsol YPF's share of the assets from the partnership. 57
During 1998, discoveries occurred in many parts of the world. Our success in Angola continued with new finds in Kissanje, Marimba, Hungo and Dikanza in Block 15. In South America, there was a successful discovery at the Tropical-1X well on the Quiriquire block in Venezuela, in which we have a 45% stake. In Norway, the Barden well confirmed significant natural gas reserves in the Southern extension of the Ormen Lange Dome. Other substantial oil and natural gas discoveries were made off the coast of Trinidad and in Egypt, Canada and the USA. Capital expenditure and acquisitions decreased to $4,212 million in 1999 from $6,318 million in 1998. In 2000, projects coming on stream are expected to include Amherstia in Trinidad and Ha'py and Baltim in Egypt. In addition, there should be a full year's production from new developments in the deepwater Gulf of Mexico. REFINING AND MARKETING <TABLE> <CAPTION> Years ended December 31, ----------------------- 1999(a) 1998(a) 1997(a) ---- ---- ---- <S> <C> <C> <C> Total replacement cost operating profit....... ($ million) 1,840 2,564 2,292 Indicative industry global refining margin.... ($/bbl) 0.91 1.74 1.81 Refinery throughputs.......................... (mb/d) 2,522 2,698 2,855 Total marketing sales ........................ (mb/d) 3,186 3,137 3,083 </TABLE> - ---------- (a) Includes BP Amoco's share of the BP/Mobil joint venture. In 1999, Refining and Marketing achieved a highly competitive adjusted return (i.e. before special charges) on fixed assets of 10% 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. After adjusting to exclude special charges of $242 million, Refining and Marketing's replacement cost operating profit was $2,082 million a decrease of 19% compared with 1998, reflecting 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. 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. 1998 was a year of strong performance for the downstream business. Underlying performance delivered total replacement cost operating profit of $2,564 million, an increase of 12% over 1997, with a competitive return on fixed assets of 12%. This outcome was achieved in spite of difficult trading conditions, characterized by reduced refining margins in the second half of the year and the impact of economic slowdown in our growth markets. 1998 also benefited from the capitalization of IT expenditure of $70 million which would have been expensed in earlier periods. Marketing volumes rose in 1998 in spite of divestments across both the retail and commercial segments, with continued improvement flowing from our US and European operations. The retail business grew during the year, with volumes up 3%. The focus on growing our convenience retailing activity as one of our key strategic objectives continued. The 'Split Second' US convenience store format was rolled out in Atlanta, Georgia; Philadelphia, Pennsylvania; Chicago, Illinois; Denver, Colorado and south Florida, with high customer satisfaction ratings. Our commercial marketing activities continued to deliver strong growth in income with the drive towards customer-focused marketing solutions. In 1998, despite lower overall margins our refining business achieved good results. A combination of cost savings and improved operating efficiency produced a 12% improvement in total replacement cost operating profit compared with 1997. 58
Capital expenditure in 1999 was $1,634 million compared with $1,937 million in 1998. The Group's capital expenditure on refinery assets, including environmental expenditures and investments in line with regulatory requirements to improve product quality, totalled $607 million in 1999 compared with $685 million in 1998. During the year we completed the repositioning of our Toledo refinery (to allow it to run on cheaper, heavy crudes) with the commissioning of a new coker unit and we began a project at Sines, Portugal, to develop a liquefied petroleum gas storage cavern facility. During the year we also began to upgrade our Bulwer Island refinery near Brisbane, Australia, to allow it to produce low sulphur fuels. This was one of a number of initiatives undertaken as part of our drive for cleaner fuels. Capital expenditure on marketing assets amounted to $1,027 million in 1999 compared with $1,252 million in the previous year. In December 1999, we announced that BP Amoco had agreed with ExxonMobil Corporation the principles under which their European fuels and lubricants joint venture would be dissolved in response to the European Commission's requirement in respect of the Exxon and Mobil merger. Under the agreement - which is conditional on a number of approvals from national governments and appropriate employee consultation - BP Amoco will purchase Mobil's 30% interest in the fuels business for around $1.5 billion, subject to adjustments. In addition, the two companies will divide the assets of the lubricants business broadly in line with their equity stakes (51% Mobil, 49% BP Amoco). In February 2000, the European Union's Merger Task Force gave its approval to the dissolution. CHEMICALS <TABLE> <CAPTION> Years ended December 31, -------------------------- 1999 1998 1997 ----- ----- ----- <S> <C> <C> <C> <C> Total replacement cost operating profit...($ million) 686 1,100 1,530 Chemicals production (a)... ............(thousand tonnes) 21,853 20,570 19,491 </TABLE> - ---------- (a) Includes BP Amoco share of associated undertakings and other interests in production. Chemicals' replacement cost operating profit was $686 million compared with $1,100 million in 1998, a decrease of 38%. After adjustment for special charges of $247 million, Chemicals' profit of $933 million in 1999 represented a decrease of 19% compared with the adjusted result of 1998 despite a 6% increase in production. Special charges in 1998 amounted to $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 1998, margins for most commodity chemicals deteriorated compared with 1997. This reflected increased industry capacity, weak demand in Europe and the financial crisis in Asia. These factors were offset to some extent by our continued focus on self-help initiatives, such as cost reduction, and by the benefits of our investment in proprietary technology. The total volume of product manufactured rose by 6% in 1998, principally reflecting our styrenics acquisition in early 1998. As a result of all these factors total replacement cost operating profit was $1,100 million compared with $1,530 million in 1997. 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 Amoco refinanced the entity's bank loans and sold its interest in the entity to ExxonMobil, resulting in a loss of $218 million ($148 million after tax). In 1998, divestments included the Adibis lubricants and fuel additives business and speciality chemicals distribution businesses in Europe and Australasia. During 1997 BP Amoco sold its advanced materials and phenolic resins business in the UK. 59
Capital expenditure and acquisitions in 1999 was $1,215 million compared with $1,606 million in 1998. 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. During 1998 we acquired Styrenix Kunststoffe. Projects completed in 1998 included the purified terephthalic acid unit and paraxylene unit at Geel, a new metaxylene plant at Texas City, and the first stage of the planned $825 million investment programme in the UK. OTHER BUSINESSES AND CORPORATE <TABLE> <CAPTION> Years ended December 31, -------------------------- 1999 1998 1997 ----- ----- ----- <S> <C> <C> <C> <C> Replacement cost operating loss........ ($ million) 826 374 524 </TABLE> Other Businesses and Corporate comprises Finance, BP Solarex, the Group's coal asset, interest income and costs relating to corporate activities worldwide. The net cost of Other Businesses and Corporate in 1999 amounted to $826 million. This included special charges of $398 million. The net cost of Other Businesses and Corporate of $374 million for 1998 included $50 million for integration costs in respect of the BP Amoco merger. 1998 benefited from the capitalization of IT expenditure amounting to $65 million which would have been expensed in earlier periods. INTEREST EXPENSE Interest expense was $1,316 million compared with $1,177 million in 1998. These amounts included special charges of $24 million and $12 million respectively, arising from the early redemption of bonds. After adjusting for these special charges, the increase in Group interest expense in 1999 reflected lower capitalized interest and higher average debt, the effects of which were partly offset by lower interest rates. Interest expense in 1998 was $1,177 million compared with $1,035 million in 1997. The increase reflected higher average debt, partly offset by lower interest rates. TAXATION The charge for corporate taxes in 1999 was $1,880 million compared with $1,520 million in 1998, and $3,013 million in 1997. The effective tax rate on historical cost profit was 27% in 1999, 32% in 1998 and 34% in 1997. The lower rate in 1999 reflected the effect of inventory holding gains not taxed, whereas in 1998 there were unrelieved inventory holding losses; this difference between the two years was partly offset by the relatively low tax relief on net exceptional losses in 1999 and the absence of tax credits in 1998. The effective tax rate on replacement cost profit before exceptional items was 28%, compared with 25% in 1998 and 30% in 1997. The increase in effective rate in 1999 over 1998 reflected the effects of tax on inventory holding gains which do not form part of the replacement cost profit before exceptional items. The reduction from 1997 to 1998 reflected the effects of tax relief on inventory holding losses and timing benefits. 60
BP AMOCO GROUP'S FINANCIAL CONDITION CASH FLOW <TABLE> <CAPTION> Years ended December 31, -------------------------- 1999 1998 1997 ----- ----- ----- ($ million) <S> <C> <C> <C> Net cash inflow from operating activities................... 10,290 9,586 15,558 Net cash (outflow) inflow................................... (82) (906) 878 </TABLE> 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 $9,586 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 return 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, 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. Acquisitions and disposals of businesses produced a net cash inflow of $243 million compared with $778 million in 1998. 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. Net cash outflow for 1998 was $906 million, compared with an inflow of $878 million in 1997. The change reflected lower operating cash flow resulting from lower income and a smaller reduction in working capital requirements than in 1997, partially offset by a turnaround in the funding position of the BP/Mobil joint venture, lower net capital expenditures and lower tax payments. Net cash inflow from operating activities fell from $15,558 million in 1997 to $9,586 million in 1998. Most of this decrease was caused by the effect on profits of the deterioration in the operating environment for all of our businesses. The requirement for funding working capital decreased in 1998 by $352 million, compared with a reduction of $1,779 million in 1997. Dividends from joint ventures and associated undertakings increased to $966 million in 1998 from $741 million in 1997, mainly as a result of improved profits from the BP/Mobil joint venture. The net cash outflow from servicing of finance and from returns on investments increased to $825 million from $655 million in 1997, principally because of the payment of dividends to minority shareholders. Tax payments fell from $2,273 million in 1997 to $1,705 million in 1998. Payments for capital expenditures on fixed assets and purchase of shares for employee share schemes, net of proceeds from sales of fixed assets, amounted to $7,298 million in 1998. This represented a small decrease over the net payments of $7,432 million in 1997. 61
Acquisitions and disposals of businesses resulted in a net cash inflow of $778 million in 1998 compared with an outflow of $2,624 million in 1997. This was due in part to an increase in disposal proceeds but principally to the funding situation with joint ventures. A turnaround in the funding position of the BP/Mobil joint venture produced net cash inflows of $708 million in 1998, whereas in 1997 the initial funding of this and certain other joint ventures caused an outflow of $1,967 million. Dividend payments decreased by $29 million to $2,408 million in 1998, reflecting an increase in distributions offset by a higher proportion of shareholders opting for the share dividend. 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 dollar debt wherever possible, achieving this by 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 $12,993 million at the end of 1999, an increase of $113 million over the year. The ratio of net debt to net debt plus equity was 23%, the same as a year ago. At December 31, 1999 contracts had been placed for authorized future capital expenditure estimated at $2,544 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, 1999, the Group had available undrawn committed borrowing facilities of $3,000 million ($2,800 million at December 31, 1998). BP Amoco 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 $4 billion or the equivalent in other currencies. At March 24, 2000, the amount drawn down against this Programme was $2,705 million. OUTLOOK Crude oil prices continue to respond to OPEC's supply side management and, though inventories have been substantially reduced, the market remains orderly. Continuing OPEC restraint, together with firm underlying demand, is expected to lead to short-term robustness in the oil price, though volatility is to be expected, dependent on weather and market sentiment. Natural gas prices are expected to show normal seasonal variation. Downstream, the development of marketing margins is expected to depend upon future movements in crude oil and hence product prices. Refining margins are expected to remain volatile. In Chemicals, margins are expected to respond to developments in feedstock costs assuming firmness in demand. Surplus industry capacity, particularly new capacity coming on stream in the second half of 2000, together with continuing euro weakness, are expected to limit upside potential. The foregoing discussion focuses on certain trends and general market and economic conditions and outlook on production levels or rates, prices and margins and, as such, are forward-looking statements that involve risk and uncertainty that could cause actual results and developments to differ materially from those expressed or implied by these discussions. 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 Amoco. 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. For a discussion of additional factors that may affect the above discussion, see Item 1 -- Description of Business -- Additional Factors Which May Affect Business. 62
FINANCIAL RISK MANAGEMENT The Group's policy is to co-ordinate certain key activities on a global basis in order to optimize its financial position and performance. These include the management of the currency, maturity and interest rate profile of borrowing, cash, other significant financial risks and relationships with banks and other financial institutions. International oil trading and risk management relating to the businesses' commercial operations are carried out by the Group's oil trading divisions. BP Amoco is exposed to financial risks, including market risk, credit risk and liquidity risk, arising from the Group's normal business activities. These risks and the Group's approach to dealing with them are discussed below. MARKET RISK Market risks include the possibility that changes in currency exchange rates, interest rates or oil and gas prices will adversely affect the value of the Group's financial assets, liabilities or expected future cash flows. Market risks are managed using a range of financial and commodity instruments including derivatives. We also trade derivatives in conjunction with these risk management activities. CURRENCY EXCHANGE RATES Fluctuations in exchange rates can have significant effects on the Group'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 for 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 and the Group's borrowings are predominantly in US dollars. Our 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-dollar exposures are managed using a range of derivatives. See Item 9A -- Quantitative and Qualitative Disclosures about Market Risk. INTEREST RATES The BP Amoco Group 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 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 (London Inter-Bank Offer Rate) interest rates as borrowings are mainly denominated in, or are swapped into, US dollars. The BP Amoco Group uses derivatives to achieve the required mix between fixed and floating rate debt. During 1999, 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 47-53%. OIL AND NATURAL GAS PRICES BP Amoco's oil trading division uses financial and commodity derivatives as part of the overall optimization of the value of the Group's equity oil production and as part of the associated trading of crude oil, products and related instruments. The Group also uses financial and commodity derivatives to manage certain of its exposures to price fluctuations on natural gas transactions. MARKET RISK MANAGEMENT AND TRADING In market risk management and 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. 63
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, cash flow 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 financial instrument and derivative activity, whether for risk management or trading, is carried out by specialist teams which have the appropriate skills, experience and supervision. These teams are subject to close financial and management control, meeting generally accepted industry practice and reflecting the principles of the Group of Thirty Global Derivatives Study recommendations. An independent control function monitors compliance with BP Amoco's 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 the Group's exposure in potentially adverse situations. Further details of BP Amoco's use of derivatives appear in Item 9A -- Quantitative and Qualitative disclosures about Market Risk, and in Item 18 -- Note 28 of Notes to Financial Statements. 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 the use of financial 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. 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 31,1999, the Group had available undrawn committed facilities of $3 billion. These committed facilities, which are mainly with a number of international banks, expire in 2000. The Group expects to renew the facilities on an annual basis. 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 economic for the Group. Losses will therefore be borne as they arise rather than being spread over time through insurance premia. The position is reviewed periodically. MILLENNIUM IT RISK The Year 2000 issue, which stems from computer programs written using two digits rather than four to define the applicable year, could have resulted in processing faults on the change of century, producing a wide range of consequences. To avoid any such consequences, BP Amoco undertook a Group-wide risk-based review of its computer systems and process control equipment and developed and implemented plans to remediate potential Year 2000-related faults by replacement or repair. The project was designed to minimize risks arising from the Year 2000 problem which might endanger health, safety, the environment, the Group's reputation or its cash flow. 64
The Year 2000 programme covered IT application systems and infrastructure, process control systems and embedded microprocessors in plants, oil and gas fields and building facilities, and an assessment of the readiness of our critical suppliers, customers, joint venturers and partners. Contingency plans were developed to manage any risk associated with our operations or third party dependencies. In the event, the Group achieved a smooth and successful transition into 2000. In addition to dealing with the specific Year 2000 risk, important additional benefits were seen from the Year 2000 programme in a number of different areas across the Group. A critical point has been passed successfully, but the Group is maintaining an appropriate level of vigilance to deal with any consequential Year 2000 effects, especially from third parties, which may yet emerge. The total cost of the Group's Year 2000 programme was $335 million, which includes some minor expenditure in the first few months of 2000. These costs are charged against income in the period in which they are incurred. 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 Amoco'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 has until now been low. The currency of accounting records and the related systems will be converted during the transition period, which ends on January 1, 2002. The capability to conduct business in national currencies will be retained as long as necessary. The costs associated with the euro programme are estimated at $100 million, of which some $26 million had been incurred and expensed by the end of 1999. It is difficult to predict whether the euro will affect the level or volatility of foreign exchange rates. However, we do not expect that the introduction of the euro will have a significant effect on the Group's results of operations, its financial position or liquidity. ENVIRONMENTAL INVESTMENT <TABLE> <CAPTION> Years ended December 31, -------------------------- 1999 1998 1997 ----- ----- ----- ($ million) <S> <C> <C> <C> Operating expenditure (a)................................... 414 446 477 Capital expenditure (b)..................................... 246 426 376 Clean-ups................................................... 92 129 129 </TABLE> - ---------- (a) Expenditure for 1999 includes $15 million (1998 $44 million and 1997 $10 million) incurred by the BP/Mobil joint venture (b) Expenditure for 1999 includes $84 million (1998 $89 million and 1997 $69 million) incurred by the BP/Mobil joint venture. 65
Operating and capital expenditure on the prevention, control, abatement or elimination of air, water and solid waste pollution is often not incurred as a separately 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. In 1999, environmental operating expenditure and amounts spent on clean-ups were slightly lower than 1998. The reduction in capital expenditure reflects the completion of a number of capital projects at the end of 1998. Similar levels of operating and capital expenditure are expected in the foreseeable future. In addition to operating and capital expenditure, we 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. 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. These provisions are usually set up on a discounted basis, as required by Financial Reporting Standard No.12, `Provisions, Contingent Liabilities and Contingent Assets'. 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 engaged in similar industries or that our competitive position will be adversely affected as a result. With effect from January 1, 1999 BP Amoco adopted Financial Reporting Standard No. 12 which requires that the Group now provide fully for the cost of decommissioning oil and gas production facilities and related pipelines on a discounted basis at the commencement of production. Further details of decommissioning and environmental provisions appear in Item 18 -- Note 27 of Notes to Financial Statements. See also Item 1 -- Description of Business -- Environmental Protection. 66
ITEM 9A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK BP Amoco 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. An independent control function monitors compliance with BP Amoco'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 Amoco's exposure in potentially adverse situations. Counterparty credit validation, independent of the dealers, is undertaken before contractual commitment. Further information about BP Amoco's use of derivatives, their characteristics, and the accounting treatment thereof is given in Item 18 -- Note 1 and Note 28 of Notes to Financial Statements. RISK MANAGEMENT FOREIGN CURRENCY EXCHANGE RATE RISK Fluctuations in exchange rates can have significant effects on BP Amoco'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 underlying economic currency of the Group's cash flows is mainly the US dollar. This is because BP Amoco's major product, oil, is priced internationally in US dollars. BP Amoco'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-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, 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, 1999 the total of foreign currency borrowings not swapped into dollars amounted to $275 million. The principal element of this is $90 million of borrowings in Malaysian ringgits. The following tables provide information about the Group's foreign currency derivative financial instruments. These include foreign currency forward exchange agreements (forwards) and cylinder option contracts (cylinders) that are sensitive to changes in the sterling/dollar exchange rate. 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. 67
For forwards, the tables present 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 dollars. The remaining contracts relate to sterling requirements for net operational expenditures. 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. For cylinders, the tables present the notional amounts of the constituent purchased call and written put option contracts at December 31, 1999 and the weighted average strike rates by contractual maturity dates. At December 31, 1999, the sterling cylinders related to the Group's expected sterling tax payments over the next year. We no longer hedge the expected sterling dividend over the next year using cylinders but hedge each quarter's sterling payment using forwards which mature within the quarter. The fair values for the foreign exchange contracts in the table below are based on market prices of comparable instruments (forwards) and pricing models which take into account relevant market data (options). 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 2000 2001 2002 Thereafter Total value ----- ----- ----- --------- ----- ----- ($ million) <S> <C> <C> <C> <C> <C> <C> 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> 68
INTEREST RATE RISK BP Amoco 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 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 Amoco Group uses derivatives to achieve the required mix between fixed and floating rate debt. During 1999, 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 47-53%. The following table shows, by major currency, the Group's borrowings at December 31, 1999 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) ($m) (%) ($m) ($m) <S> <C> <C> <C> <C> <C> <C> 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, 1999. 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, 2000, the Group's 2000 earnings before taxes would decrease by approximately $80 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, 1999 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. 69
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 Amoco'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> 1999 --------------------------------------- High Low Average December 31 ----- ------ ------- ----------- ($ million) <S> <C> <C> <C> <C> Oil price contracts......... 5 3 3 5 </TABLE> NATURAL GAS PRICE RISK BP Amoco'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, 1999, in addition to the swaps contracts shown in the table there were options contracts with aggregate notional amounts of $7 million and terms of up to one year. 70
<TABLE> <CAPTION> Weighted Fair value average price Contract ----------------- ----------------- Quantity amount Asset Liability Receive Pay -------- -------- ------- --------- ------- ------- (Btus trillion)(a) ($ million) ($ million) ($ per mmbtu)(b) <S> <C> <C> <C> <C> <C> <C> 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 (btus) (b) Million british thermal units (mmbtu) TRADING In conjunction with the risk management activities discussed above, BP Amoco 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 Amoco'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. This activity is monitored and measured separately from the risk management activity and is subject to maximum value at risk limits authorized by the board. 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 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. 71
The following table shows values at risk for trading activities. <TABLE> <CAPTION> 1999 --------------------------------------- High Low Average December 31 ------ ----- ------- ----------- ($ million) <S> <C> <C> <C> <C> Interest rate contracts..... 1 -- 1 -- Foreign exchange contracts.. 13 -- 3 1 Oil price contracts......... 15 5 9 10 </TABLE> 72
ITEM 10 -- DIRECTORS AND OFFICERS OF REGISTRANT There are currently 22 directors on the board. <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 H L Fuller.................... Executive co-chairman (a) December 1998 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 September 1991 executive) Dr J G S Buchanan............. Executive director October 1996 R F Chase..................... Executive director (Deputy group March 1992 chief executive) W D Ford........................ Executive director January 2000 Dr C S Gibson-Smith........... Executive director September 1997 R L Olver..................... Executive director January 1998 B K Sanderson................. Executive director April 1992 R S Block..................... Non-executive director (a)(b)(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) 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)(d) 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 and Mr W G Lowrie were appointed executive directors and Mrs R S Block, Mr J H Bryan, Mr E B Davis, Jr, Mr R J Ferris, Mr F A Maljers, Dr W E Massey and Mr M H Wilson were appointed non-executive directors of BP Amoco with effect from December 31, 1998. Mr H L Fuller was appointed executive co-chairman of the board on the same date. Mr W G Lowrie resigned as a director of BP Amoco on February 12, 1999. Mr W D Ford was appointed executive director with effect from January 1, 2000. Mr H L Fuller will resign from the Board with effect from March 31, 2000. BP Amoco'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 Dr J G S Buchanan, R F Chase, C F Knight and The Lord Wright of Richmond. Mr W D Ford is standing for election by the shareholders. 73
The biographies of the directors and the secretary are set out below. P D Sutherland, SC -- Peter Sutherland (53) 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 of Goldman Sachs International and is a non-executive director of Telefonaktiebolaget LM Ericsson, Investor AB and ABB. He is on the advisory board of the Council on Foreign Relations and is chairman of the Overseas Development Council. H L Fuller -- Larry Fuller (61) was appointed a director of Amoco in 1981 and was elected chairman and chief executive officer in February 1991. He is a non-executive director of Chase Manhattan Corporation, Chase Manhattan Bank, Motorola, Security Capital Group and Abbott Laboratories. He also serves on the boards of Catalyst, the American Petroleum Institute and the Rehabilitation Institute of Chicago, and is a trustee of The Orchestral Association. Sir Ian Prosser -- Sir Ian (56) joined BP's board in 1997 and was appointed deputy chairman in February 1999. He is chairman and chief executive of Bass, a non-executive director of SmithKline Beecham and vice president of the council of the Brewers and Licensed Retailers Association. Sir John Browne, F. Eng, -- Sir John (52) 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 DaimlerChrysler. 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 (56), 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 (56), 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 (56), chief executive, refining and marketing, was appointed an executive director of BP Amoco with effect from January 2000. Before the merger of BP 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 (54), executive director, policies and technology, was appointed an executive director of BP in 1997. He is a non-executive director of Lloyds TSB. R L Olver -- Dick Olver (53), chief executive, exploration and production, was appointed an executive director of BP in January 1998. He is a non-executive director of Reuters Group. B K Sanderson, CBE -- Bryan Sanderson (59), chief executive, chemicals, was appointed an executive director of BP in 1992. He is chairman of Sunderland PLC, a non-executive director of Corus, president of CEFIC (the European Chemical Industry Council) and vice president of the court of governors of the London School of Economics. R S Block -- Ruth Block (69) 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 (63) joined Amoco's board in 1982. He is chairman and chief executive officer 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 (55) joined Amoco's board in 1991. He is president and chief executive officer of Alliant Energy. He is a non-executive director 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 Iowa Business Council, the Edison Electric Institute and the Nuclear Energy Institute. He is also a trustee of Carnegie Mellon University. R J Ferris -- Richard Ferris (63) joined Amoco's board in 1981. He retired as co-chairman of Doubletree Corporation in 1997. He is a non-executive director of The Proctor & Gamble Company. 74
C F Knight -- Charles Knight (64) joined BP's board in 1987. He is chairman and chief executive officer 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 (66) joined Amoco's board in 1994. He is a member of the supervisory boards of SHV Holding, Vendex N.V. and KLM Royal Dutch Airlines. He is chairman of the supervisory board of the Amsterdam Concertgebouw and Rotterdam School of Management, Erasmus University. Dr W E Massey -- Walter Massey (61) 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 (63) joined BP's board in 1994. He is chairman of Johnson Matthey and a non-executive director of ING Baring Holdings and BICC. Sir Robin Nicholson, F Eng, FRS -- Sir Robin (65) joined BP's board in 1987. He retired as chairman of Pilkington Optronics in November 1998. He is a non-executive director of Rolls-Royce and a member of the UK Government's Council for Science and Technology. M H Wilson -- Michael Wilson (62) joined Amoco's board in 1993. He is vice chairman and a director of RBC Dominion Securities. He is a non-executive director of Manufacturers Life Insurance Company and Rio Algom. Sir Robert Wilson,KCMG -- Sir Robert (56) 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 (68) joined BP's board in 1991, having been Permanent Under-Secretary and Head of the UK Diplomatic Service. He is a non-executive director of De La Rue. J C Hanratty -- Judith Hanratty (56) joined BP in London in 1986 and was appointed company secretary in October 1994. She is a nominated member of the Council of Lloyds (the London Insurance Market), a member of the Competition Commission (formerly the Monopolies and Mergers Commission), the Listing Authorities Committee of The London Stock Exchange and the Takeover Panel. She is also a governor of the College of Law and a Fellow of Lucy Cavendish College, Cambridge. ITEM 11 -- COMPENSATION OF DIRECTORS AND OFFICERS INTRODUCTION During the 12 months following the merger between BP and Amoco, the Remuneration Committee of the board (the Committee) has undertaken a comprehensive review of the way in which it determines the remuneration of executive directors and of the effectiveness of its policies for the needs of the merged company. BP Amoco competes globally for business and for customers, with each business stream of the Company now exceeding most FTSE companies in size. It also competes globally for talent, with fewer than half of its top management team being of British nationality. In its review the Committee was assisted by a team of independent consultants in a study of other global-scale companies, with a particular emphasis on those based in Europe. Having taken account of that study, and of the development of the Company, the Committee has concluded that an individual director's home nationality should be regarded as of secondary importance in setting remuneration. Therefore, in order to ensure greater equity at board level, all executive directors will now have their potential remuneration set against global competitive comparisons, irrespective of their own nationality. The remuneration of BP Amoco's directors will continue to be compared with the remuneration of directors in their own countries (in companies of appropriate scale and global spread) to ensure that remuneration policies and practices remain competitive in the home market. Further rigorous comparisons will then be made against an international set of appropriate companies. The Committee has also decided that the remuneration of executive directors should in future be managed separately from that of other senior executives. Shareholders' agreement will be sought for the creation of an Executive Directors' Incentive Plan for their remuneration. Directors will then be excluded from future participation in any other incentive plans. The following information relates specifically to the reward of executive directors, unless stated otherwise. 75
CHANGES MADE DURING 1999 There have been two immediate outcomes of the changes to the Company's reward philosophy for executive directors. The first has been a set of adjustments to base salaries during 1999, which have also affected annual incentive bonuses for the year. Secondly, long-term incentive grants in the 1997 and 1998 Long Term Performance Plans (LTPPs) have been adjusted to provide a means of reducing the imbalance in rewards between former BP and former Amoco directors following the merger. These potential long-term plan awards are in line with plans approved by shareholders in late 1998. PROPOSED CHANGES IN 2000 The major change proposed for 2000 is the introduction of the Executive Directors' Incentive Plan which will provide for the granting of performance shares, share options and cash incentives at the discretion of the Remuneration Committee. The Committee proposes to introduce two component plans under the umbrella of the Executive Directors' Incentive Plan - a long-term performance plan and a stock option plan. The first plan will mirror the existing plan for senior executives in the Company while the option plan will be structured to extend the timescale of the performance-reward linkage. The proposed target structure for the two component plans is set out under `Performance measures and targets for 2000', which shows the updated competitor set for the long-term plan measure, and gives outline details of the annual incentive plan targets for 2000 and of the performance condition that is under consideration for the granting of share options. No changes are proposed in the way the Long Term Performance Plan will operate for executive directors. The rules of the current Plan were approved by shareholders in November 1998. Future grants to directors under the Executive Directors' Incentive Plan will be managed in the same way and subject to the same targets and conditions, including the plan design feature which requires directors to build up a personal shareholding in the Company equal in value to at least five times their annual salary. In 1998, when shareholders approved the current BP Amoco Share Option Plan, it was considered appropriate to maintain the competitive focus on the oil sector, and it was therefore unnecessary to grant share options to UK directors who participated in the Long Term Performance Plan. Share options were granted in addition to LTPP only to North American directors, as is normal practice in North America. A number of factors have now changed. First, to meet the board's new emphasis on setting the potential rewards of all executive directors at a more equitable level of global competitiveness, there is a consequent need to increase the scale of long-term incentive grants for some directors. In coming to the conclusion that this could be best achieved through use of share options, in addition to the LTPP grants, the emphasis has been on how best to drive performance forward in the coming years. The LTPP will still predominate as the Company's long-term incentive vehicle, and it has already helped BP Amoco to achieve the aims of maximizing performance through all cycles in the oil sector. In addition to maintaining that performance, it was felt appropriate to incorporate a new level of `stretch' into long-term incentives through the use of a new and very challenging performance measure, the FTSE Global 100 group of companies. This wider competitor set gives BP Amoco's executive directors greater exposure to competition with non-oil sector performance, as well as creating better alignment with shareholders by giving increased exposure to the absolute performance of the equity market itself. (The LTPP measures relative performance.) Taking all this into account, the board favours a policy of making a balance of grants under both the three-year LTPP and the longer-term share option plan, i.e. following the approach which is currently taken in respect of our US executive directors. The remuneration policy for the most senior executives below board level will be aligned with the policy for executive directors, albeit with a stronger focus on national market comparisons. In particular, share option grants under the 1998 Plan may be made to senior executives in addition to their participation in the Long Term Performance Plan and irrespective of their nationality. 76
The remainder of this item contains details of awards made in 1999 under the incentive compensation plans of BP Amoco, and includes the remuneration data required by the London Stock Exchange. The summary contains the following sections: -- Reward philosophy. -- Reward process - the Remuneration Committee. -- Description of the reward plans. -- Performance measures and targets for 2000. -- Report on 1999 - remuneration data for executive directors. -- Long-term incentive awards. -- Other remuneration features. -- Remuneration of non-executive directors. REWARD PHILOSOPHY The remuneration of executive directors in BP Amoco will be based on the following guiding principles: -- total potential rewards will be set at levels sufficient to retain high-calibre and high-potential staff who will have alternative employment opportunities within a global market. -- total potential rewards will be earned by the achievement of demanding performance targets based on measures which represent the best interests of the shareholders in the short, medium and long term. -- incentive plans, performance targets and participating conditions will be structured to ensure that directors will be fully aligned with the best interests of the Company at all stages of the business cycle. -- levels of reward for meeting business targets will be fully competitive within the appropriate market while outstanding rewards will be given for delivering world-class results. -- remuneration policies and incentive plans will be designed to meet the highest standards of international industry. REWARD PROCESS -- THE REMUNERATION COMMITTEE The Remuneration Committee's role is to determine the terms of engagement and remuneration of the group chief executive and the executive directors. The Remuneration Committee (the Committee) also establishes the principles for the remuneration of other senior executives, which in turn provide the framework for remunerating all employees. At the beginning of the year the Committee sets challenging and demanding performance targets for the executive directors and at the end of the year makes awards which reflect the year's performance. The Committee members have no personal financial interest, other than as shareholders, in the matters to be decided. They have no conflicts arising from cross-directorships or day-to-day involvement in running BP Amoco. For membership of the Committee see Item 10 -- Directors and Officers of Registrant. The Committee actively solicits professional advice from independent outside consultants. The constitution and operation of the Committee are in compliance with the `Principles of Good Governance and Code of Best Practice' set out by the London Stock Exchange (the `Combined Code'). Ernst & Young have confirmed that the scope of their report on the accounts covers the disclosures contained in this report that are specified for audit by the London Stock Exchange 77
DESCRIPTION OF THE REWARD PLANS BASE SALARY -- This is a fixed sum, payable monthly in pensionable cash, recognizing ongoing market worth. -- Salaries are reviewed annually in line with global companies, and targeted at the median of the appropriate national survey groups for fully effective job performance. Higher salaries are paid only where justified by sustained higher level of individual contribution. -- Surveys are conducted on a regular basis by a leading remuneration consultancy and look at remuneration levels in an international mix of companies with comparable size, complexity and global spread of operations. ANNUAL PERFORMANCE BONUS -- This is a variable sum, potentially awarded annually in non-pensionable cash. (Bonuses to North American executives are pensionable/ benefits-bearing). -- It recognizes performance against demanding annual targets set out in annual performance contracts. -- Target bonus level for executive directors is 70% of base salary in 2000. If contract levels of performance are achieved so that the target bonus is earned, executive annual remuneration levels reach a median position of the relevant global employment market. -- A `stretch' bonus level is also identified for when targets are substantially exceeded. (For directors, this is 105% of salary in 1999.) -- Outstanding performance may be recognized by bonus payments in excess of the stretch level at the discretion of the Committee. LONG-TERM INCENTIVE -- The Long Term Performance Plan consists of rolling, three-year performance periods, at the beginning of which participants receive a grant of performance units. -- Any potential LTPP award is a variable, taxable sum, in shares, given after the performance period. (Depending on the technical constraints in each country in which the Plan is operated, the Committee may award shares to participants or fund the purchase of shares by participants.) -- Share awards have a minimum of a further three years' retention in trust and no shares will be released until the director has a personal holding in BP Amoco shares, within the Plans, equivalent to five times base salary. SHARE OPTIONS -- Share options may be granted in proportion to the ranking of the Company by total shareholder return over a three-year period relative to the FTSE Global 100 set of companies. Options will vest three years after grant without further performance conditions. PERFORMANCE MEASURES AND TARGETS FOR 2000 ANNUAL PERFORMANCE BONUS -- Bonus targets focus on internal operating plans and are a mix of financial targets and leadership objectives. The financial targets concentrate on savings in cash costs and bonus underlying performance improvement relative to competitors and market expectations, while the leadership objectives include safety, environment, people, organization and investment issues. -- These targets are embedded within performance contracts which reflect the operating plans of the Company, and are subject to board decision. 78
-- Each year's performance provides the platform for the next year's targets, providing a continuous drive to higher levels of achievement. LONG-TERM PERFORMANCE PLAN (LTPP) -- The LTPP focuses on performance within the oil sector and looks at performance against demanding three-year shareholder return, profitability and growth targets. -- For all three measures BP Amoco's performance is assessed in relation to the oil majors: Chevron, ENI, ExxonMobil, Repsol YPF, Royal Dutch Shell, Texaco and TotalFina. -- The maximum award can be made only when performance has been ahead of the competitor group on all three performance measures. For second and lower rankings progressively lower awards are made. Participants benefit only when they deliver results above the median for this group. SHARE OPTIONS -- Option grants will be related to performance comparisons with a wide selection of global companies. 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 in setting the scale of grants. -- Options granted to former Amoco employees during 1999-2000 will not be subject to any additional performance conditions, in line with the practice followed previously in Amoco. (Under the terms of the merger agreement, options granted to former Amoco Group employees must, for at least two years, be no less favourable than their previous arrangements.) REPORT ON 1999 -- REMUNERATION DATA FOR EXECUTIVE DIRECTORS BASE SALARY AWARDS IN 1999 Base salaries for executive directors were adjusted in two steps during the year by a total average increase of 22% to reflect the increased scale and complexity of directors' responsibilities. 79
BONUS AWARDS FOR 1999 PERFORMANCE The Committee established a bonus rating of 148% based on the achievement of targets set for 1999. This rating took into account, among other things, the operating performance of the Company which reflected the substantial benefits of restructuring and integration following the merger, together with ongoing cost control; the saving of cash costs and the substantial contribution of performance improvements to the results for the year; the return on average capital employed and earnings per share, which were both strong and very competitive in the sector; and the progress made against non-financial targets. Bonus awards for executive directors were therefore significantly higher than in 1998. Annual remuneration for 1999 is shown in the table below. <TABLE> <CAPTION> Annual Benefits performance and other 1999 1998 Base salary bonus emoluments Total Total ---------- ---------- ---------- ---------- ---------- ($ thousand) <S> <C> <C> <C> <C> <C> Sir John Browne............... 1,120 1,137 94 2,351 1,514 Dr J G S Buchanan............. 657 673 70 1,400 899 R F Chase..................... 737 754 61 1,552 962 H L Fuller (a)................ 1,096 1,302 36 2,434 1,674 Dr C S Gibson-Smith........... 579 590 62 1,231 838 W G Lowrie (a)................ 188 126 4 318 1,049 R L Olver (b)................. 587 596 68 1,251 948 B K Sanderson................. 668 685 80 1,433 987 ---------- ---------- ---------- ---------- ---------- Totals 5,632 5,863 475 11,970 8,871 ========== ========== ========== ========== ========== </TABLE> ---------- The table above represents annual remuneration earned by, and paid to, executive directors in the 1999 financial year, with the exception of bonuses (which were earned in 1999 but paid in 2000). A conversion rate of L1 = $1.62 has been used for 1999, L1 = $1.66 for 1998. 70% target bonus applied in 1999 to all executive directors except H L Fuller (80% target/120% maximum). (a) H L Fuller and W G Lowrie were appointed to the board on December 31, 1998, the effective date of the merger. However, the figures shown represent earnings for the whole 1998 calendar year. (b) R L Olver was appointed to the board on January 1, 1998. His benefits and other emoluments for 1998 include expatriation costs which were incurred before his board appointment. 80
LONG-TERM INCENTIVE AWARDS BP AMOCO LONG TERM PERFORMANCE PLAN Awards made in 1999 under the BP Long Term Performance Plan related to the 1996-98 Plan. Estimates of grant values were indicated in BP Amoco's 1998 Annual Report on Form 20-F. Awards to be made in 2000 under the BP Long Term Performance Plan relate to the 1997-99 Plan. BP Amoco came first in the 1997-99 Plan, and the Remuneration Committee expects to make a maximum award. The primary performance measure, BP Amoco's shareholder return against the market (SHRAM), was 15%. BP Amoco was the only company in the peer group to exceed market returns during the three-year period, and was more than 20% ahead of the nearest-ranked competitor. At the time of the merger the Committee decided to set minimum award levels for all participants in the 1998 Plans, including executive directors. This decision was based on pre-merger announcement comparisons of total shareholder returns, and provides an indication for participants that the final outcome will be no less than the SHRAM performance measure position which BP held, in relation to its peer group comparators, before the merger. As mentioned previously, some executive directors have also had additional grants, under these plans, to bring them closer to a common global standard. The total number of shares that may be awarded to all directors under the 1997-99 Plan is 2,190,600, with a value of $16.8 million based on a share price of L4.81/$7.65 at L1 = $1.59 (mid-market price on February 14, 2000). Serving recipients in the LTPP are obliged to have the balance of their 1997-99 awards retained in trust for at least a further three years. This restriction also applies to future Plans, together with additional share ownership requirements. Potential awards to executive directors, including an indicative range of potential awards under the 1998 and 1999 Plans, for which awards would be payable in 2001 and 2002, are set out in the table below. LONG-TERM PERFORMANCE PLANS <TABLE> <CAPTION> Performance period of Plan 1996-98 1997-99 1998-2000 1999-2001 -------- ------------------- ---------------- ---------------- Year of award 1999 2000 2000 2001 2002 -------- -------- ------- ---------------- ---------------- Range of potential awards(d) ----------------------------------- Value of Potential Award award(a) award(b) value(c) Minimum Maximum Target Maximum -------- --------- ----- ------- ------- ------ ------- ($ thousand) (shares) ($ thousand) (shares) (shares) <S> <C> <C> <C> <C> <C> <C> <C> CURRENT EXECUTIVE DIRECTORS Sir John Browne......... 1,500 527,600 4,036 80,280 532,600 270,000 540,000 Dr J G S Buchanan....... 1,188 323,400 2,474 47,700 319,800 160,000 320,000 R F Chase............... 1,500 329,800 2,523 51,540 339,000 180,000 360,000 W D Ford................ -- -- -- -- -- 100,000 200,000 H L Fuller.............. -- -- -- -- -- 270,000 540,000 Dr C S Gibson-Smith..... 1,030 285,800 2,186 45,480 297,400 144,000 288,000 R L Olver............... 876 285,800 2,186 45,480 297,400 144,000 288,000 B K Sanderson........... 1,500 329,800 2,523 51,540 339,000 160,000 320,000 FORMER EXECUTIVE DIRECTORS OF BP S J Ahearne............. 500 -- -- -- -- -- -- K R Seal................ 1,000 54,200 415 -- -- -- Dr R W H Stomberg....... 1,000 54,200 415 -- -- -- -- -------- -------- ------- -------- -------- -------- -------- </TABLE> - ---------- (a) Based on average market price on date of award (L5.70/$9.23) at L1 = $1.62. (b) Based on assessed performance and the other terms of the Plan. (c) Based on mid-market price of BP Amoco shares on February 14, 2000 (L4.80/$7.65 at L1 = $1.59). (d) Minimum awards were determined for these Plans prior to the completion of the merger. Actual awards will be determined at the end of each performance period. 81
OTHER REMUNERATION FEATURES SHARE OPTION AWARDS DIRECTORS' EXECUTIVE SHARE OPTIONS(a) <TABLE> <CAPTION> Number of options ----------------------------------------------------- At At Dates January 1, December 31, Average from which Expiry 1999(b) Granted(b) Exercised(b) 1999 option price(c) exercisable dates ---------- ------- --------- ----------- ------------ ----------- ------ (L) <S> <C> <C> <C> <C> <C> <C> <C> Dr J G S Buchanan.. 119,200 -- 119,200(d) -- n/a n/a n/a W D Ford.......... -- -- -- 4,536,444(e) 3.23(f) 3/22/94-3/15/01 3/22/03-3/14/09 H L Fuller........ 14,768,400 1,087,844 794,000 15,062,244 3.05(f 4/23/93-3/15/01 4/23/01-3/14/09 DIRECTOR LEAVING THE BOARD IN 1999 W G Lowrie........ 7,066,600 -- -- 7,066,600(h) ---------- ------- --------- ----------- ------------ ----------- ------ </TABLE> (a) All options in the above table are denoted in BP Amoco ordinary stock or calculated equivalents. (b) Directors' positions adjusted for October 1999 subdivision of ordinary share capital. (c) 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. (d) 96,000 exercised at L1.375 and 23,200 exercised at L1.69 (market price at date of exercise L4.6425). (e) On appointment on January 1, 2000. (f) Equivalent to $5.23 (W D Ford) and $4.94 (H L Fuller) at L1 = $1.62. (g) 132,332 ADSs exercised at $19.81 (market price at date of exercise $53.88). (h) At February 12, 1999 DIRECTORS' SAYESHARE OPTIONS <TABLE> <CAPTION> Number of options ----------------------------------------------------- At At Dates January 1, December 31, Average from which Expiry 1999(a) Granted(a) Exercised(a) 1999 option price(b) exercisable dates ---------- ------- --------- ----------- ------------ ----------- ------ L <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..... 6,978 750 -- 7,728 3.03 9/1/99-9/1/04 2/29/00-2/28/05 R F Chase............. 9,324 -- -- 9,324 1.85 9/1/00 2/28/01 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 9/1/01-9/1/02 2/28/02-2/28/03 B K Sanderson........ 8,534 -- 4,284(c) 4,250 2.11 9/1/99-9/1/02 2/29/00-2/28/03 </TABLE> (a) Directors' positions adjusted for October 1999 subdivision of ordinary share capital. (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) Exercised at L1.61 (market price at date of exercise L5.875). SHARE SCHEMES AND OTHER BENEFITS In 1999, six UK directors were allocated shares under the BP Participating Share Scheme which is available to most UK employees. Under the Participating Scheme, the Company matches employees' own contribution of shares, all of which are held for a defined period (see Item 18 -- Note 33 of Notes to Financial Statements). Six directors continued to participate in the Savings-Related Share Option Scheme, under which employees enter a savings plan to purchase shares after three or five years. This plan is also open to most UK employees. UK directors may also receive modest benefits from typical all-employee arrangements, such as a fuel discount card and free accidental death insurance. 82
Mr Fuller and Mr Lowrie were eligible to participate in those benefit plans generally provided to US employees, including an employee savings plan containing a company matching contribution of up to 7% of annual earnings, and certain health and welfare plans, including medical and dental coverage, non-contributory group life insurance of one times annual earnings, additional employee paid group life insurance, and short- and long-term sickness and disability coverage. In 1999, the Company contributed $112,787 and $42,430 respectively to the Savings Plan to `match' their savings. PENSIONS UK DIRECTORS Pension and other benefits have regard to competitor practice in the home country of each senior executive. In the UK, eligible staff can join the BP Pension Scheme, which offers Inland Revenue-approved retirement benefits, based on final salary. Scheme members' core benefits, which are non-contributory, comprise a pension accrual rate of 1/60th of final basic salary for each year of service, inclusive of a proportion of the basic state pension, up to a limit of two-thirds of final basic salary; a lump-sum death-in-service benefit of three times salary; and a dependant's benefit of two-thirds of actual or prospective pension. The link between the Scheme pension and the basic state pension will cease for all members on May 1, 2000. Normal retirement age is 60, but members who have 30 or more years' service at the age of 55 can opt to retire early without an actuarial reduction to their pension. Post-retirement pensions are reviewed annually, and increases are guaranteed equivalent to the Retail Price Index (up to 5%). Directors who are members of the BP Pension Scheme accrue pension at the enhanced rate of 2/60ths of their final basic salary for each year of service as managing directors (up to the same two-thirds limit). No contributions are payable by executive directors. None of the directors is affected by the `pensionable earnings cap'. The BP Pension Scheme is the principal section of the BP Pension Fund, the latter being established under a trust deed. Contributions to the Fund are made on the advice of the actuary appointed by the Trustee directors. No contributions were made to the Fund by the Company in 1999 in respect of pensions accruing under the BP Pension Scheme. US DIRECTORS All current US directors participate in the Employee Retirement Plan for Amoco Corporation. Under this retirement plan, the amount of the annuity which they are eligible to receive on a single-life basis is determined under an annuity benefit formula. The annuity benefit formula (including a percentage of US Social Security benefits) is calculated at 1.67% x the employee's 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 annual earnings. Years of participation in the Plan in excess of 36 do not result in additional benefits. Normal pensionable age in the US Plan 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. In line with US tax regulations, benefits are provided as appropriate through a combination of tax qualified and restoration/non-qualified plans. 83
PENSION ENTITLEMENT - UK EXECUTIVE DIRECTORS <TABLE> <CAPTION> Additional Additional pension earned pension earned Accrued during the during the Years of service entitlement at year ended year ended at December 31, December 31, December 31, December 31, 1999 1999(a) 1999(a) 1998(a) ------------- -------------- -------------- -------------- ($ thousand) ($ thousand) ($ thousand) <S> <C> <C> <C> <C> Sir John Browne........... 33 880 252 45 Dr J G S Buchanan......... 30 447 118 32 R F Chase................. 35 551 128 32 Dr C S Gibson-Smith....... 29 393 95 27 R L Olver................. 26 416 115 27 B K Sanderson............. 35 486 63 32 </TABLE> - ---------- (a) A conversion rate of L1 = $1.62 has been used for 1999, L1 = $1.66 for 1998. PENSION ENTITLEMENT - US EXECUTIVE DIRECTORS <TABLE> <CAPTION> Additional Additional pension earned pension earned Accrued during the during the Years of service entitlement at year ended year ended at December 31, December 31, December 31, December 31, 1999 1999 1999 1998 ------------- -------------- -------------- -------------- ($ thousand) ($ thousand) ($ thousand) <S> <C> <C> <C> <C> H L Fuller................... 38 1,172 (a) 26 128 W G Lowrie................... 33 491 (b) 16 111 - ---------- </TABLE> (a) Includes a temporary annuity payable until age 62 of $7,092. (b) Includes a temporary annuity payable until age 62 of $6,704. Accrued entitlement as at Apri1 1,1999 (date of retirement). 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 before 1996 and have contracts which include a two-year notice period. The Board does not consider it in shareholders' interest to renegotiate these contracts. Mr Sanderson's contract is due to expire in 2000 when he reaches the age of 60. Under each contract, the Company reserves the right to make a payment in lieu of notice. Dr Stomberg was a director of BP prior to his retirement at the end of 1997 and served as a special adviser to the group chief executive on European matters at a fixed annual salary of DM1.1 million until the end of 1999. Mr Fuller's and Mr Lowrie's secondments to BP Amoco began on December 31, 1998. Their underlying US employment agreements with BP Amoco Corporation have a three-year period. Mr Fuller is due to retire in March 2000. Mr Lowrie's UK secondment was subject to termination by mutual agreement, after which he would return to the USA and be subject to the terms of that US employment agreement. His secondment terminated on Apri1 1,1999, and he received a payment of $6,126,414 in line with the terms of his US agreement. On his appointment as an executive director, Mr Ford's contractual arrangements were adjusted to provide for termination on one year's notice and retirement at 60. Mr Ford's salary in this post is $620,000. If his contract is terminated by the Company without cause, Mr Ford will be entitled to compensation of $1 million a year (pro rated for part years) for each year remaining between the date of severance and the date he turns 60. As an expatriate, Mr Ford receives a resettlement allowance of $450,000 a year which terminates on December 31, 2002. 84
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 1999 the non-executive co-chairman of BP Amoco received a fee of $259,000 (L160,000). The non-executive directors of BP Amoco received an annual fee of $65,000 (L40,000) plus an allowance of $4,860 (L3,000) for occasions on which a director travels across the Atlantic for a board meeting or committee meeting. During 1999 the board met 11 times, eight times in the UK and three times in the USA. Committee meetings are held in conjunction with board meetings whenever feasible. Details of individual fees are set out below. 85
REMUNERATION OF NON-EXECUTIVE DIRECTORS <TABLE> <CAPTION> Year ended Year ended December 31, 1999(a) December 31, 1998 ----------------- ----------------- ($ thousand) CURRENT DIRECTORS <S> <C> <C> R S Block............................................ 89 90 J H Bryan............................................ 84 90 E B Davis, Jr........................................ 89 90 R J Ferris........................................... 84 90 C F Knight........................................... 79 51 (b) F A Maljers.......................................... 70 90 Dr W E Massey........................................ 89 90 H M P Miles.......................................... 79 61 (b)(c) Sir Robin Nicholson.................................. 79 (d) 46 (b)(e) Sir Ian Prosser...................................... 122 55 (b) P D Sutherland....................................... 259 (f) 266 (b) M H Wilson........................................... 94 90 Sir Robert Wilson.................................... 79 18 (b) The Lord Wright of Richmond.......................... 75 (g) 61 (b) DIRECTORS WHO RETIRED BEFORE 1999 D R Beall............................................ -- 393 (h) Sir James Glover..................................... 81 (i) 61 (b) Dr K N Horn.......................................... 36 (i) 51 (b) A C Martinez......................................... -- 244 (j) M R Seger............................................ -- 393 (h) Sir Patrick Sheehy................................... 89 (i) 51 (b) T M Solso............................................ -- 214 (k) ------ ------ Total................................................ 1,577 2,595 ====== ====== </TABLE> - ---------- (a) Sterling payments converted at the average 1999 exchange rate of L1 = $1.62. (b) Sterling payments converted at the average 1998 exchange rate of L1 = $1.66. (c) Paid in part to his employer. (d) Also received $32,000 (L20,000 converted at the average 1999 exchange rate of L1 = $1.62) for serving on the Technical Advisory Council. (e) Also received $22,687 (L13,667 converted at the average 1998 exchange rate of L1 = $1.66) for serving on the Technical Advisory Council. (f) Also received other remuneration and benefits of $9,849 (L6,080 converted at the average 1999 exchange rate of L1 = $1.62). (g) Also received $1,458 (L900 converted at the average 1999 exchange rate of L1 = $1.62) for serving as a director of BP Pensions Trustees Limited. (h) Includes standard Amoco Corporation non-executive director remuneration of $89,762 and a special payment of $304,000 in recognition of service to the Amoco Corporation board. (i) Ex gratia payment in lieu of superannuation in recognition of contribution to the board of The British Petroleum Company p.l.c. (j) Includes standard Amoco Corporation non-executive director remuneration of $89,762 and a special payment of $154,000 in recognition of service to the Amoco Corporation board. (k) Includes standard Amoco Corporation non-executive director remuneration of $89,762 and a special payment of $124,000 in recognition of service to the Amoco Corporation board. TOTAL EMOLUMENTS Total emoluments include salary and benefits earned and paid during the relevant financial year, plus bonuses, which are paid in the following year, plus for 1999 the value of the awards made under the 1997-99 Plan in respect of the three years covered by that Plan. The total remuneration paid during 1999 to all directors and the secretary as a group was $21,502,000. 86
ITEM 12-- OPTIONS TO PURCHASE SECURITIES FROM REGISTRANT OR SUBSIDIARIES (a) Pursuant to the various BP Amoco Group share option schemes, the following options for Ordinary Shares of the Company were outstanding at March 24, 2000: <TABLE> <CAPTION> Expiry Exercise Options dates of price outstanding options per share ------------ ------------ ------------ (shares) <S> <C> <C> 312,425,993 2000 to 2010 $2.09 to $10.10 </TABLE> Options under the BP Amoco Share Option Plan were granted to Mr Fuller in 1999. See Item 11 -- Compensation of Directors and Officers. As at March 24, 2000, the following directors, together with the secretary of BP Amoco p.l.c., held options under the BP Amoco Group share option schemes for Ordinary Shares or their calculated equivalent as set out below: <TABLE> <CAPTION> <S> <C> Sir John Browne............... 5,968 J G S Buchanan................ 5,586 R F Chase..................... 9,324 W D Ford...................... 4,536,444 H L Fuller................... 15,062,244 C S Gibson-Smith.............. 2,154 R L Olver..................... 6,856 B K Sanderson................. 4,250 J C Hanratty.................. 9,324 ---------- Total......................... 19,642,150 ========== </TABLE> - ---------- (a) See also Item 18-- Note 33 of Notes to Financial Statements. ITEM 13 -- INTEREST OF MANAGEMENT IN CERTAIN TRANSACTIONS 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, 1999 to March 24, 2000. 87
PART III ITEM 15 -- DEFAULTS UPON SENIOR SECURITIES None. ITEM 16 -- CHANGES IN SECURITIES, CHANGES IN SECURITY FOR REGISTERED SECURITIES AND USE OF PROCEEDS BP Amoco p.l.c.'s Articles of Association were amended by special resolution on September 1,1999. The 'Description of BP Amoco Ordinary Shares' and 'Description of BP Amoco American Depositary Shares' contained in BP Amoco's Report on Form 6-K filed on March 27, 2000, are incorporated herein by reference. 88
PART IV ITEM 18 -- FINANCIAL STATEMENTS See pages F-3 through F-97 and page S-1, incorporated herein by reference. ITEM 19 -- FINANCIAL STATEMENTS AND EXHIBITS (A) 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> Page <S> <C> Reports of Independent Auditors and Consents of Independent Auditors.... F-1 Consolidated Statement of Income for the Years Ended December 31, 1999, 1998 and 1997................................ F-3 Consolidated Balance Sheet at December 31, 1999 and 1998................ F-4 Consolidated Statement of Cash Flows for the Years Ended December 31, 1999, 1998 and 1997................................ F-5 Statement of Total Recognized Gains and Losses for the Years Ended December 31, 1999, 1998 and 1997................................ F-5 Statement of Changes in BP Amoco Shareholders' Interest for the Years Ended December 31, 1999, 1998 and 1997...................... F-6 Notes to Financial Statements........................................... F-8 Supplementary Oil and Gas Information (Unaudited)....................... F-85 Schedule for the Years Ended December 31, 1999, 1998 and 1997 Schedule II Valuation and Qualifying Accounts......................... S-1 </TABLE> (B) EXHIBITS The following documents are filed as part of this annual report: <TABLE> <CAPTION> Page <S> <C> Computation of Ratio of Earnings to Fixed Charges (Unaudited)........... E-1 Memorandum and Articles of Association of BP Amoco p.l.c (embodying amendments to September 1, 1999)........................... E-2 </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. 89
SIGNATURES Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the Registrant certifies that it meets all of the requirements for filing on Form 20-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized. BP AMOCO p.l.c. (REGISTRANT) /s/ Judith C. Hanratty (SECRETARY) Dated: March 29, 2000 90
BP AMOCO p.l.c. AND SUBSIDIARIES 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, 1999 and 1998, and the related consolidated statements of income, changes in BP Amoco shareholders' interest, total recognized gains and losses, and cash flows for each of the three years in the period ended December 31, 1999. Our audits also included the financial statement schedule listed in the Index at Item 19(a). 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. The consolidated financial statements for each of the two years in the period ended December 31,1998 give retroactive effect to the merger of The British Petroleum Company p.l.c. and Amoco Corporation, which has been accounted for as a merger. We did not audit the financial statements of Amoco Corporation for the year ended December 31,1997, which statements reflect net income constituting approximately 33% of the related consolidated financial statement total for the year ended December 31, 1997. Those statements, which were prepared in accordance with accounting principles generally accepted in the United States, were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to amounts included for Amoco Corporation for 1997 (before the conversion to accounting principles generally accepted in the United Kingdom), is based solely on the report of the other auditors. We conducted our audits in accordance with United Kingdom auditing standards which do not differ in any significant respect from United States generally accepted auditing standards. 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 (including the conversion of the financial statements of Amoco Corporation to accounting principles generally accepted in the United Kingdom). We believe that our audits provide a reasonable basis for our opinion. In our opinion, based on our audits and the report of other auditors, 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, 1999 and 1998, and the consolidated results of its operations and its consolidated cash flows for each of the three years in the period ended December 31, 1999, 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 44 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 15, 2000 ---------------------------------------------------------------------- CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference of our report dated February 15, 2000, 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, 1999 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 and 333-79399) of BP Amoco p.l.c. /s/ ERNST&YOUNG London, England Ernst & Young March 29, 2000 F - 1
BP AMOCO p.l.c. AND SUBSIDIARIES REPORT OF INDEPENDENT ACCOUNTANTS To: THE BOARD OF DIRECTORS AND Shareholders of Amoco Corporation In our opinion, the consolidated statements of income and cash flows (not presented separately herein) present fairly, in all material respects the results of the operations and the cash flows of Amoco Corporation and its subsidiaries for the year ended December 31, 1997, in conformity with generally accepted accounting principles. These financial statements are the responsibility of Amoco Corporation's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. /s/ PricewaterhouseCoopers LLP Chicago, Illinois February 24, 1998 --------------------------------------------------------------------------- CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-21868, 333-9020, 333-9798 and 333-79399) of BP Amoco p.l.c. and in the Prospectuses constituting part of the Registration Statements on Form F-3 (No. 33-39075 and 33-20338) of BP America and BP Amoco p.l.c. and (No. 33-29102) of The Standard Oil Company and BP Amoco p.l.c. and (No. 333-9790) of BP Amoco p.l.c. of our report dated February 24, 1998, appearing in Item 19 of this Annual Report on Form 20-F. /s/ PricewaterhouseCoopers LLP PRICEWATERHOUSECOOPERS LLP Chicago, Illinois March 29, 2000 F - 2
BP AMOCO p.l.c. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF INCOME <TABLE> <CAPTION> Years ended December 31, ------------------------ Note 1999 1998 1997 ------ ------ ------ ------ ($ million, except per share amounts) <S> <C> <C> <C> TURNOVER............................................. 101,180 83,732 108,564 Less: Joint ventures................................. 17,614 15,428 16,804 ------ ------ ------ GROUP TURNOVER....................................... 2 83,566 68,304 91,760 Replacement cost of sales............................ 68,615 56,270 73,828 Production taxes..................................... 3 1,017 604 1,307 ------ ------ ------ GROSS PROFIT......................................... 13,934 11,430 16,625 Distribution and administration expenses............. 4 6,064 6,044 6,742 Exploration expense.................................. 548 921 962 ------ ------ ------ 7,322 4,465 8,921 Other income......................................... 5 414 709 662 ------ ------ ------ GROUP REPLACEMENT COST OPERATING PROFIT.............. 7,736 5,174 9,583 Share of profits of joint ventures................... 555 825 544 Share of profits of associated undertakings.......... 603 522 556 ------ ------ ------ TOTAL REPLACEMENT COST OPERATING PROFIT.............. 8,894 6,521 10,683 Profit (loss) on sale of businesses.................. 6 (421) 395 127 Profit (loss) on sale of fixed assets................ 6 84 653 313 Restructuring costs.................................. 6 (1,943) -- -- Merger expenses...................................... 6 -- (198) -- Refinery network rationalization..................... 6 -- -- (47) European refining and marketing joint venture implementation..................................... 6 -- -- (265) ------ ------ ------ REPLACEMENT COST PROFIT BEFORE INTEREST AND TAX...... 6,614 7,371 10,811 Inventory holding gains (losses)..................... 1,728 (1,391) (939) ------ ------ ------ HISTORICAL COST PROFIT BEFORE INTEREST AND TAX....... 8,342 5,980 9,872 Interest expense..................................... 7 1,316 1,177 1,035 ------ ------ ------ PROFIT BEFORE TAXATION............................... 7,026 4,803 8,837 Taxation............................................. 9 1,880 1,520 3,013 ------ ------ ------ PROFIT AFTER TAXATION................................ 5,146 3,283 5,824 Minority shareholders' interest...................... 138 63 151 ------ ------ ------ PROFIT FOR THE YEAR*................................. 5,008 3,220 5,673 Dividend requirements on preference shares*.......... 2 1 1 ------ ------ ------ PROFIT FOR THE YEAR APPLICABLE TO ORDINARY SHARES*... 5,006 3,219 5,672 ====== ====== ====== PROFIT PER ORDINARY SHARE - CENTS Basic ............................................... 11 25.82 16.77 29.56 Diluted.............................................. 11 25.68 16.70 29.41 ====== ====== ====== DIVIDENDS PER ORDINARY SHARE - CENTS................. 10 20.0 19.8 18.0 ====== ====== ====== Average number outstanding of 25 cents ordinary shares (in millions)...................................... 19,386 19,192 19,184 ====== ====== ====== </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 44. The Notes to Financial Statements are an integral part of this Statement. F - 3
BP AMOCO p.l.c. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET <TABLE> <CAPTION> December 31, --------------------------------- Note 1999 1998 ------ --------------- ---------------- ($ million) <S> <C> <C> <C> <C> <C> FIXED ASSETS Intangible assets................. 19 3,344 3,037 Tangible assets................... 20 52,631 54,880 Investments Joint ventures Gross assets................... 9,948 9,053 Gross liabilities.............. 4,744 4,048 ------ ------ Net investment................. 21 5,204 5,005 Associated undertakings.......... 21 4,334 4,162 Other............................ 21 571 605 ------ ------ 10,109 9,772 ------ ------ TOTAL FIXED ASSETS.................. 66,084 67,689 CURRENT ASSETS Inventories....................... 22 5,124 3,642 Trade receivables................. 23 9,417 5,778 Other receivables falling due Within one year.................. 23 3,930 3,626 After more than one year......... 23 3,455 3,305 Investments....................... 24 220 470 Cash at bank and in hand.......... 1,331 405 ------ ------ 23,477 17,226 ------ ------ CURRENT LIABILITIES -- FALLING DUE WITHIN ONE YEAR Finance debt...................... 25 4,900 4,114 Trade payables.................... 26 8,203 5,091 Other accounts payable and accrued liabilities....................... 26 10,172 10,238 ------ ------ 23,275 19,443 ------ ------ NET CURRENT ASSETS (LIABILITIES).... 202 (2,217) ------ ------ TOTAL ASSETS LESS CURRENT LIABILITIES 66,286 65,472 Noncurrent liabilities Finance debt...................... 25 9,644 9,641 Accounts payable and accrued liabilities....................... 26 2,245 2,047 Provisions for liabilities and charges Deferred taxation................. 9 1,783 1,632 Other............................. 27 8,272 8,579 ------ ------ 21,944 21,899 ------ ------ NET ASSETS.......................... 44,342 43,573 Minority shareholders' interest..... 1,061 1,072 ------ ------ BP AMOCO SHAREHOLDERS' INTEREST*.... 43,281 42,501 ====== ====== REPRESENTED BY: Capital shares Preference........................ 21 21 Ordinary.......................... 4,871 4,842 Paid in surplus..................... 29 3,684 3,386 Merger reserve...................... 29 697 697 Retained earnings................... 30 34,008 33,555 ------ ------ 43,281 42,501 ====== ====== </TABLE> - ---------- * A summary of the adjustments to BP Amoco 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 44. The Notes to Financial Statements are an integral part of this Balance Sheet. F - 4
BP AMOCO p.l.c. AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS <TABLE> <CAPTION> Years ended December 31, ------------------------ Note 1999 1998 1997 ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> NET CASH INFLOW FROM OPERATING ACTIVITIES............ 31 10,290 9,586 15,558 ------ ------ ------ DIVIDENDS FROM JOINT VENTURES........................ 949 544 190 ------ ------ ------ DIVIDENDS FROM ASSOCIATED UNDERTAKINGS............... 219 422 551 ------ ------ ------ SERVICING OF FINANCE AND RETURNS ON INVESTMENTS Interest received.................................... 179 223 243 Interest paid........................................ (1,065) (961) (911) Dividends received................................... 34 43 13 Dividends paid to minority shareholders.............. (151) (130) -- ------ ------ ------ NET CASH OUTFLOW FROM SERVICING OF FINANCE AND RETURNS ON INVESTMENTS............................. (1,003) (825) (655) ------ ------ ------ TAXATION UK corporation tax................................... (559) (391) (500) Overseas tax......................................... (701) (1,314) (1,773) ------ ------ ------ TAX PAID............................................. (1,260) (1,705) (2,273) ------ ------ ------ CAPITAL EXPENDITURE AND FINANCIAL INVESTMENT Payments for fixed assets............................ (6,457) (8,431) (8,600) Purchase of shares for employee share schemes........ (77) (254) (300) Proceeds from the sale of fixed assets............... 18 1,149 1,387 1,468 ------ ------ ------ NET CASH OUTFLOW FOR CAPITAL EXPENDITURE AND FINANCIAL INVESTMENT (5,385) (7,298) (7,432) ------ ------ ------ ACQUISITIONS AND DISPOSALS Investments in associated undertakings............... (197) (396) (1,021) Acquisitions......................................... 17 (102) (314) -- Net investment in joint ventures..................... (750) 708 (1,967) Proceeds from the sale of businesses................. 18 1,292 780 364 ------ ------ ------ NET CASH INFLOW (OUTFLOW) FOR ACQUISITIONS AND DISPOSALS 243 778 (2,624) ------ ------ ------ EQUITY DIVIDENDS PAID................................ (4,135) (2,408) (2,437) ------ ------ ------ NET CASH (OUTFLOW) INFLOW ........................... (82) (906) 878 ====== ====== ====== FINANCING............................................ 31 (954) (377) 1,012 MANAGEMENT OF LIQUID RESOURCES....................... 31 (93) (596) (167) INCREASE IN CASH..................................... 31 965 67 33 ------ ------ ------ (82) (906) 878 ====== ====== ====== </TABLE> - -------------------------------------------------------------------------------- STATEMENT OF TOTAL RECOGNIZED GAINS AND LOSSES <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> PROFIT FOR THE YEAR.................................. 5,008 3,220 5,673 Currency translation differences..................... (921) 55 (1,587) ------ ------ ------ TOTAL RECOGNIZED GAINS AND LOSSES RELATING TO THE YEAR 4,087 3,275 4,086 ====== ====== Prior year adjustment -- change in accounting policy.. 715 ------ Total recognized gains and losses.................... 4,802 ====== </TABLE> - --------------- For a cash flow statement and a statement of comprehensive income prepared on the basis of US GAAP see Note 44 -- US generally accepted accounting principles. - -------------------------------------------------------------------------------- The Notes to Financial Statements are an integral part of these Statements. F - 5
BP AMOCO p.l.c. AND SUBSIDIARIES STATEMENT OF CHANGES IN BP AMOCO SHAREHOLDERS' INTEREST On October 4, 1999 the parent company's authorised share capital of 12 billion ordinary shares of 50 cents each was subdivided into 24 billion ordinary shares of 25 cents amounting to $6 billion. Also outstanding are preference shares of L12,750,000 ($21 million). Also during the year 51,842,146 ordinary shares were issued under the share dividend plan by capitalization of the share premium account and 66,162,232 ordinary shares were issued under employee share schemes. The authorized ordinary share capital of BP Amoco p.l.c. at December 31, 1998 was 12 billion ordinary shares of 50 cents each and at December 31, 1997 the authorised ordinary share capital was 7,949 million ordinary shares of 25 pence each. The allotted share capital at December 31, was as follows: <TABLE> <CAPTION> Shares --------------------- Authorized Issued Amount ----------- --------- -------- ($ million) <S> <C> <C> <C> NON-EQUITY-- PREFERENCE SHARES 8% cumulative first preference shares of L1 each at December 31, 1999, 1998 and 1997.... 7,250,000 7,232,838 12 =========== ========= ======== 9% cumulative second preference shares of L1 each at December 31, 1999, 1998 and 1997.... 5,500,000 5,473,414 9 =========== ========= ======== EQUITY--ORDINARY SHARES OF 25 CENTS EACH Authorized December 31, 1999............................... 24,000,000,000 ============== </TABLE> <TABLE> <CAPTION> Years ended December 31, ---------------------------------------------------------------------------- 1999 1998 1997 ---------------------- ---------------------- ---------------------- ISSUED Shares of Shares of Shares of 25 cents each Amount 50 cents each Amount 50 cents each Amount ------------- ------ ------------- ------ ------------- ------ (thousands) ($ million) (thousands) ($ million) (thousands) ($ million) <S> <C> <C> <C> <C> <C> <C> January 1................ 19,366,020 4,842 9,597,793 4,309 9,598,573 4,361 Employee share schemes... 66,162 16 29,833 13 40,407 18 Share dividend plan...... 51,842 13 110,285 46 87,179 36 Share repurchases........ -- -- (54,901) (27) (128,366) (64) Redenomination of shares into US dollars....... -- -- -- 484 -- -- Exchange adjustment...... -- -- -- 17 -- (42) ------------- ------ ------------- ------ ------------- ------ December 31.............. 19,484,024 4,871 9,683,010 4,842 9,597,793 4,309 ============= ====== ============= ====== ============= ====== PAID IN SURPLUS January 1................ 3,386 3,777 3,733 Premium on shares issued: Employee share schemes. 311 117 144 Share dividend plan ... (13) (46) (36) Exchange adjustment...... -- 22 (64) Redenomination of shares into US dollars......... -- (484) -- ------ ------ ------ December 31.............. 3,684 3,386 3,777 ====== ====== ====== </TABLE> The Notes to Financial Statements are an integral part of this Statement. F - 6
BP AMOCO p.l.c. AND SUBSIDIARIES STATEMENT OF CHANGES IN BP AMOCO SHAREHOLDERS' INTEREST (CONCLUDED) <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> MERGER RESERVE January 1.......................................... 697 650 673 Employee share schemes............................. -- 97 92 Share repurchases.................................. -- (50) (115) ------ ------ ------ December 31........................................ 697 697 650 ====== ====== ====== RETAINED EARNINGS January 1.......................................... 33,555 33,746 32,231 Profit for the year................................ 5,008 3,220 5,673 Exchange adjustment................................ (921) 16 (1,481) Share repurchases.................................. -- (507) (1,243) Dividends (c) Preference (non-equity)........................... (2) (1) (1) Ordinary (equity)................................. (3,882) (4,120) (3,451) Qualifying Employee Share Ownership Trust (d)...... (61) (42) -- Share dividend plan................................ 311 1,243 907 ------ ------ ------ December 31........................................ 34,008 33,555 32,635 ====== ====== Prior year adjustment - change in accounting policy (Note 43)................................. 1,111 ------ December 31, 1997-- as restated.................... 33,746 ====== </TABLE> - ---------- (a) During 1999, 51,842,146 Ordinary Shares (1998, 110,285,094 and 1997, 87,179,495) were 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 L5 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. (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 - 7
BP AMOCO p.l.c. AND SUBSIDIARIES 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.12 `Provisions, Contingent Liabilities and Contingent Assets' (FRS12) and Financial Reporting Standard No.13 `Derivatives and Other Financial Instruments: Disclosures' (FRS13) with effect from January 1,1999. The financial information for 1998 and 1997 has been restated to comply with the requirements of FRS12. See Note 43 for further information. BASIS OF PREPARATION The Group's main activities are the exploration and production of crude oil and natural gas; 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 associated undertaking, 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. F - 8
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 1 -- ACCOUNTING POLICIES (CONTINUED) 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. REPLACEMENT COST The results of individual businesses and geographical areas are presented on a replacement cost basis. Replacement cost operating results exclude stock holding gains or losses and reflect the average cost of supplies incurred during the year, and thus provide insight into underlying trading results. Stock 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. FOREIGN CURRENCIES On consolidation, assets and liabilities of subsidiary undertakings 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 subsidiary and associated undertakings 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, as are all oil price derivatives, and accounted for using the fair value method. 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. F - 9
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 1 -- ACCOUNTING POLICIES (CONTINUED) DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED) 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. 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. F - 10
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 1 -- ACCOUNTING POLICIES (CONTINUED) 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. 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. F - 11
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 1 -- ACCOUNTING POLICIES (CONCLUDED) 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. 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 restated to conform with the 1999 presentation. NOTE 2 -- TURNOVER <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and operating revenue.......................... 91,891 76,448 100,913 Customs duties and sales taxes....................... 8,325 8,144 9,153 ------ ------ ------ 83,566 68,304 91,760 ====== ====== ====== </TABLE> NOTE 3 -- PRODUCTION TAXES <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> UK petroleum revenue tax............................. 237 45 306 Overseas production taxes............................ 780 559 1,001 ------ ------ ------ 1,017 604 1,307 ====== ====== ====== </TABLE> F - 12
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 4 -- DISTRIBUTION AND ADMINISTRATION EXPENSES <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Distribution......................................... 5,031 4,714 5,178 Administration....................................... 1,033 1,330 1,564 ------ ------ ------ 6,064 6,044 6,742 ====== ====== ====== </TABLE> NOTE 5 -- OTHER INCOME <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Income from other fixed asset investments............ 66 74 101 Other interest and miscellaneous income.............. 348 635 561 ------ ------ ------ 414 709 662 ====== ====== ====== Income from investments publicly traded included above 14 10 19 ------ ------ ------ </TABLE> NOTE 6 -- EXCEPTIONAL ITEMS Exceptional items comprise profit (loss) on sale of businesses and fixed assets, restructuring costs, merger expenses, refinery network rationalization costs and European refining and marketing joint venture implementation costs as follows: <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Profit on sale of businesses - --Group................................................. 427 310 250 - --Joint ventures........................................ 42 85 -- Loss on sale of businesses - --Group................................................. (890) -- -- - --Joint ventures........................................ -- -- (123) ------ ------ ------ (421) 395 127 Profit (loss) on sale of fixed assets -- Group.......... 84 653 313 ------ ------ ------ (337) 1,048 440 Restructuring costs -- Group............................ (1,900) -- -- Restructuring costs -- Joint ventures................... (43) -- -- Merger expenses -- Group................................ -- (198) -- Refinery network rationalization -- Group............... -- -- (47) European refining and marketing joint venture implementation -- Group............................... -- -- (265) ------ ------ ------ Exceptional items....................................... (2,280) 850 128 Taxation credit (charge): Sale of businesses...................................... (21) (36) (7) Sale of fixed assets.................................... (29) (185) (208) Restructuring costs..................................... 280 -- -- Merger expenses......................................... -- 23 -- Refinery network rationalization........................ -- -- 24 European refinery and marketing joint venture implementation -- -- 53 ------ ------ ------ Exceptional items, net of tax........................... (2,050) 652 (10) ====== ====== ====== </TABLE> F - 13
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) SALES OF BUSINESSES AND FIXED ASSETS The profit on sale of businesses during 1999 relates 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 is mainly attributable to the disposal by the BP/Mobil joint venture of its retail network in Hungary. The major elements of the loss on sale of businesses or termination of operations in 1999 are the disposal by the Group of its interest in the Pedernales oil field in Venezuela and the closure of its paraxylene joint venture in Singapore. For 1999 the sale of fixed assets includes 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 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 relates mainly to the disposal by the BP/Mobil joint venture of its retail network in Belgium. 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. In 1997 the major disposals were the sale of US exploration and production properties and an intrastate natural gas pipeline in Texas. Other divestments included oil marketing assets in Thailand and advanced materials and plastic resin businesses in the UK. The loss on sale of businesses by joint ventures related principally to the costs of the BP/Mobil joint venture terminating base oil manufacturing operations at Llandarcy in the UK. Additional information on the sale of businesses and fixed assets is given in Note 18 - Disposals. RESTRUCTURING COSTS These costs arising 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 the year was $976 million. MERGER EXPENSES BP Amoco incurred fees and expenses of $198 million in connection with the merger. These costs relate principally to investment banking fees as well as legal, accounting and regulatory filing fees. REFINERY NETWORK RATIONALIZATION The net charge for refinery network rationalization in 1997 of $47 million (1996 $24 million) represents the balance of the costs associated with the rationalization of the BP Amoco Group's international refining system announced in 1995. EUROPEAN REFINING AND MARKETING JOINT VENTURE IMPLEMENTATION The one-off costs associated with the setting up of the European refining and marketing joint venture with Mobil in 1997 were $265 million. These costs represent the BP Amoco Group's share of charges for severance, restructuring, rebranding and other implementation charges. F - 14
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 7 -- INTEREST EXPENSE <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Bank loans and overdrafts............................ 119 158 188 Other loans.......................................... 854 762 651 Finance leases....................................... 75 90 102 ------ ------ ------ 1,048 1,010 941 Capitalized.......................................... 43 119 116 ------ ------ ------ Group................................................ 1,005 891 825 Joint ventures....................................... 70 54 -- Associated undertakings.............................. 131 108 83 Unwinding of discount on provisions (Note 43)........ 130 124 127 Change in discount rate for provisions (Note 43)..... (20) -- -- ------ ------ ------ Total charged against profit......................... 1,316 1,177 1,035 ====== ====== ====== </TABLE> Interest expense includes a charge of $24 million (1998 $12 million and 1997 nil) relating to early redemption of debt. NOTE 8 -- DEPRECIATION AND AMOUNTS PROVIDED Included in the income statement under the following headings: <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Depreciation: Replacement cost of sales.......................... 4,185 4,666 4,631 Distribution....................................... 408 335 390 Administration..................................... 115 100 88 Exceptional items.................................. 258 -- 8 ------ ------ ------ 4,966 5,101 5,117 ====== ====== ====== Depreciation of capitalized leased assets included above 70 71 76 ------ ------ ------ Amounts provided against fixed asset investments: Exceptional items.................................. 84 -- -- Replacement cost of sales.......................... (1) 200 -- ------ ------ ------ 83 200 -- ====== ====== ====== </TABLE> 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 $200 million. In assessing the value in use of potentially impaired assets, a discount rate of 10% has been used. F - 15
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 9 -- TAXATION CHARGE FOR TAXATION <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> United Kingdom corporation tax: Current at 30.25% (1998 at 31.0% and 1997 at 31.5%) 875 1,325 1,329 Overseas tax relief................................ (363) (566) (777) ------ ------ ------ 512 759 552 Deferred at 30.0% (1998 at 31.0% and 1997 at 31.5%) 91 (188) 217 ------ ------ ------ 603 571 769 Advance corporation tax............................ -- (76) (116) ------ ------ ------ 603 495 653 ------ ------ ------ Overseas: Current............................................ 1,143 896 2,247 Deferred........................................... 30 (4) 7 Joint ventures..................................... 5 (15) -- Associated undertakings............................ 99 148 106 ------ ------ ------ 1,277 1,025 2,360 ------ ------ ------ Taxation charge for the year......................... 1,880 1,520 3,013 ====== ====== ====== </TABLE> Included in the charge for the year is a credit of $230 million (1998 $198 million charge and 1997 $138 million charge) relating to exceptional items. PROVISIONS FOR DEFERRED TAXATION <TABLE> <CAPTION> Gross potential Provisions liability --------------- --------------- Years ended December 31, --------------------------------- 1999 1998 1999 1998 ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Analysis of movements during the year: At January 1........................................ 1,632 1,183 6,618 5,817 Exchange adjustments................................ 30 37 (42) 20 Charge (credit) for the year........................ 121 (192) 563 177 Deletions/transfers................................. -- 604 -- 604 ------ ------ ------ ------ At December 31...................................... 1,783 1,632 7,139 6,618 ====== ====== ====== ====== of which -- United Kingdom......................... 1,015 927 1,482 1,577 -- Overseas............................... 768 705 5,657 5,041 ====== ====== ====== ====== </TABLE> F - 16
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 9 -- TAXATION (CONTINUED) <TABLE> <CAPTION> Gross potential Provisions liability --------------- --------------- Years ended December 31, --------------------------------- 1999 1998 1999 1998 ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Analysis of provision: Depreciation........................................ 2,567 2,413 10,279 9,905 Petroleum revenue tax............................... (332) (420) (332) (420) Other timing differences............................ (452) (328) (2,808) (2,834) Advance corporation tax............................. -- (33) -- (33) ------ ------ ------ ------ 1,783 1,632 7,139 6,618 ====== ====== ====== ====== </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, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> United Kingdom................................................. (185) (40) 83 Overseas....................................................... 627 409 43 ------ ------ ------ 442 369 126 ====== ====== ====== </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, ------------------------ 1999 1998 1997 ------ ------ ------ (% of profit before tax) <S> <C> <C> <C> United Kingdom statutory tax rate................................. 30 31 31 Increase (decrease) resulting from: Current year timing differences not provided (including current year losses unrelieved/prior year losses utilized).... (10) (6) (4) Tax on inventory holding gains (relief for inventory holding losses)............................................... 2 (3) (1) Overseas taxes at higher rates.................................. 5 4 4 Tax credits..................................................... -- (2) (2) Advance corporation tax......................................... -- (1) (1) Other........................................................... 1 2 3 ------ ------ ------ Effective tax rate on replacement cost profit before exceptional items............................................. 28 25 30 ====== ====== ====== </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 - 17
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 9 -- TAXATION (CONCLUDED) EFFECTIVE TAX RATE <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Analysis of profit before taxation: United Kingdom....................................... 1,663 2,269 3,305 Overseas............................................. 5,363 2,534 5,532 ------ ------ ------ 7,026 4,803 8,837 ====== ====== ====== Taxation............................................. 1,880 1,520 3,013 ====== ====== ====== Effective tax rate................................... 27% 32% 34% ====== ====== ====== </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, ------------------------ 1999 1998 1997 ------ ------ ------ (% of profit before tax) <S> <C> <C> <C> United Kingdom statutory tax rate.................... 30 31 31 Increase (decrease) resulting from: Current year timing differences not provided....... (9) (12) (3) (Prior year losses utilized) current year losses unrelieved................................ 2 5 (2) (Inventory holding gains not taxed) no relief for inventory holding losses......................... (5) 5 2 Overseas taxes at higher rates..................... 5 7 6 Tax credits........................................ -- (2) (2) Advance corporation tax............................ -- (2) (1) Amortization of purchase price allocation.......... 1 1 1 Other ............................................. 3 (1) 2 ------ ------ ------ Effective tax rate................................... 27 32 34 ====== ====== ====== </TABLE> F - 18
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 10 -- DIVIDENDS PER ORDINARY SHARE <TABLE> <CAPTION> Years ended December 31, -------------------------------------------------------------- 1999 1998 1997 1999 1998 1997 1999 1998 1997 ------ ------ ------ ------ ------ ------ ------ ------ ------ (pence per share) (cents per share) ($ million) BP AMOCO <S> <C> <C> <C> <C> <C> <C> <C> <C> <C> Dividends per ordinary share: First quarterly........... 3.069 -- -- 5.00 -- -- 970 -- -- Second quarterly.......... 3.112 -- -- 5.00 -- -- 970 -- -- Third quarterly........... 3.033 -- -- 5.00 -- -- 971 -- -- Fourth quarterly.......... 3.125 3.059 -- 5.00 5.00 -- 971 968 -- ------ ------ ------ ------ ------ ------ ------ ------ ------ 12.339 3.059 -- 20.00 5.00 -- 3,882 968 -- ------ ------ ------ ------ ------ ------ ------ ------ ------ BP Dividends per ordinary share: First quarterly........... 2.875 2.625 4.75 4.25 551 490 Second quarterly.......... 3.000 2.750 5.00 4.48 579 517 Third quarterly........... 3.000 2.750 5.00 4.61 584 519 Fourth quarterly.......... -- 2.875 -- 4.70 -- 543 ------ ------ ------ ------ ------ ------ 8.875 11.00 14.75 18.04 1,714 2,069 ------ ------ ------ ------ ------ ------ AMOCO Dividends per common stock: First quarterly........... 18.75 17.50 362 345 Second quarterly.......... 18.75 17.50 360 349 Third quarterly........... 18.75 17.50 358 344 Fourth quarterly.......... 18.75 17.50 358 344 ------ ------ ------ ------ 75.0 70.00 1,438 1,382 ------ ------ ------ ------ Total Group............... 3,882 4,120 3,451 ===== ===== ====== </TABLE> On an ordinary share equivalent basis, the Amoco quarterly dividends for 1998 were 4.7 cents and 1997 4.4 cents. F - 19
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 11 -- PROFIT PER ORDINARY SHARE <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ (cents per share) <S> <C> <C> <C> Basic earnings per share....................................... 25.82 16.77 29.56 Diluted earnings per share..................................... 25.68 16.70 29.41 </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 weighted average number of shares has been adjusted for the subdivision (2 for 1 share split) of ordinary shares effective October 4, 1999. The profit attributable to ordinary shareholders is $5,006 million (1998 $3,219 million and 1997 $5,672 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, ------------------------ 1999 1998 1997 ------ ------ ------ (shares million) <S> <C> <C> <C> Weighted average number of ordinary shares..................... 19,386 19,192 19,184 Ordinary shares issuable under employee share schemes.......... 111 84 98 ------ ------ ------ 19,497 19,276 19,282 ====== ====== ====== </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, ------------------------ 1999 1998 1997 ------ ------ ------ (cents per share) <S> <C> <C> <C> Profit for the year......................................... 25.82 16.77 29.56 Inventory holding (gains) losses............................ (8.91) 7.25 4.89 ------ ------ ------ Replacement cost profit for the year........................ 16.91 24.02 34.45 Exceptional items, net of tax............................... 10.57 (3.40) 0.06 ------ ------ ------ Replacement cost profit before exceptional items............ 27.48 20.62 34.51 ====== ====== ====== </TABLE> F - 20
BP AMOCO p.l.c. AND SUBSIDIARIES 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, 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 ======= ======= ======= ======= Year ended December 31, 1998 First quarter............................. 21,516 1,376 639 3.32 Second quarter............................ 20,969 1,845 991 5.17 Third quarter............................. 21,651 2,279 1,578 8.22 Fourth quarter............................ 19,596 480 12 0.06 ------- ------- ------- ------- Total..................................... 83,732 5,980 3,220 16.77 ======= ======= ======= ======= </TABLE> NOTE 13 -- RENTAL EXPENSE UNDER OPERATING LEASES <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Minimum rentals: Tanker charters.................................... 357 396 447 Plant and machinery................................ 509 429 335 Land and buildings................................. 271 315 268 ------ ------ ------ 1,137 1,140 1,050 Less: Rentals from sub-leases........................ (178) (105) (99) ------ ------ ------ 959 1,035 951 ====== ====== ====== </TABLE> NOTE 14 -- RESEARCH AND DEVELOPMENT Expenditure on research and development amounted to $310 million (1998 $412 million and 1997 $382 million). F - 21
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 15 -- AUDITORS' REMUNERATION <TABLE> <CAPTION> Years ended December 31, -------------------------------------------------- 1999 1998 1997 --------------- --------------- --------------- UK Total UK Total UK Total ------ ------ ------ ------ ------ ------ ($million) <S> <C> <C> <C> <C> <C> <C> Audit fees -- Ernst & Young: Group audit........................ 5.5 13.5 5.8 12.1 3.9 8.9 Local statutory audit and quarterly review................. 1.0 6.1 0.8 5.1 0.7 4.2 ------ ------ ------ ------ ------ ------ 6.5 19.6 6.6 17.2 4.6 13.1 ------ ------ ------ ------ ------ ------ Audit fees -- PricewaterhouseCoopers LLP: Group audit........................ -- -- 0.1 2.7 0.1 2.8 Local statutory audit and quarterly review................. -- -- 0.2 0.9 0.2 1.1 ------ ------ ------ ------ ------ ------ -- -- 0.3 3.6 0.3 3.9 ------ ------ ------ ------ ------ ------ Total Group.......................... 6.5 19.6 6.9 20.8 4.9 17.0 ====== ====== ====== ====== ====== ====== Fees for other services -- Ernst & Young Acquisitions and disposals......... 3.4 4.5 1.7 4.2 2.5 2.5 Taxation services.................. 1.4 5.9 0.8 2.6 -- 2.1 Consultancy and other.............. 10.2 25.9 6.2 18.4 2.4 13.2 ------ ------ ------ ------ ------ ------ 15.0 36.3 8.7 25.2 4.9 17.8 ====== ====== ====== ====== ====== ====== </TABLE> 1999 Group audit fees include $1.1 million (1998 $0.7 million) for excess of actual over estimated fees for 1998. Fees to major firms of accountants other than Ernst & Young for non-audit services amounted to $160 million (1998 $181 million and 1997 $175 million). NOTE 16 -- CURRENCY EXCHANGE GAINS AND LOSSES Accounted net foreign currency exchange losses included in the determination of profit for the year amounted to $17 million gain (1998 $23 million loss and 1997 $126 million loss). F - 22
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 17 -- ACQUISITIONS In 1999 the Group acquired the outstanding 83% of ProGas, a major Canadian natural gas supply aggregator, and 50% of Solarex, a manufacturer and developer of photovoltaic products and systems, it did not already own. Also in 1999 the Group purchased APEX, a solar electric company based in Montpellier, France. During 1998 the Group acquired Styrenix Kunststoffe, a plastics business based in Germany and a number of minor refining and marketing businesses. In 1997 BP Amoco and Shell Oil completed the formation of Altura Energy, a partnership combining their oil and gas interests in west Texas and southeast New Mexico, USA. Altura Energy is consolidated within these accounts. The cost of acquisitions in the Group cash flow statement comprises: <TABLE> <CAPTION> Year ended December 31, ------------------------------------------------- 1999 1998 1997 ---------------------------- ----- ----- Book Fair Fair Fair value Adjustment value value value ----- ---------- ----- ----- ----- ($ million) <S> <C> <C> <C> <C> <C> Goodwill......................................... -- 20 20 38 -- Other intangible assets.......................... 3 -- 3 1 -- Tangible assets.................................. 109 10 119 194 810 Fixed assets - investments....................... 9 -- 9 71 -- Working capital.................................. 15 -- 15 27 25 MSI.............................................. (1) -- (1) -- (835) ------ ------ ------ ------ ------ 135 30 165 331 -- Finance debt..................................... (58) -- (58) (17) -- ------ ------ ------ ------ ------ Cash consideration............................... 77 30 107 314 -- Cash acquired.................................... 5 -- 5 -- -- ------ ------ ------ ------ ------ Net cash outflow................................. 72 30 102 314 -- ====== ====== ====== ====== ====== </TABLE> F - 23
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 18 -- DISPOSALS 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. In 1997, the major disposals were the sale of US exploration and production properties and an intrastate natural gas pipeline in Texas. Other divestments included oil marketing assets in Thailand and advanced materials and phenolic resin businesses in the UK. Total proceeds received for disposals represent the following amounts shown in the cash flow statement: <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Proceeds from the sale of businesses................. 1,292 780 364 Proceeds from the sale of fixed assets............... 1,149 1,387 1,468 ------ ------ ------ 2,441 2,167 1,832 ====== ====== ====== </TABLE> The disposals comprise the following: <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Intangible assets.................................... 199 151 21 Tangible assets...................................... 2,340 945 1,184 Fixed asset -- investments........................... 206 157 40 Working capital...................................... 175 88 203 Other ............................................... (94) (125) (110) ------ ------ ------ 2,826 1,216 1,338 Profit (loss) on sale of businesses.................. (463) 310 250 Profit (loss) on sale of fixed assets................ 84 653 313 ------ ------ ------ Total consideration.................................. 2,447 2,179 1,901 Deferred consideration............................... (12) (9) (69) Cash transferred on sale............................. 6 (3) -- ------ ------ ------ Net cash inflow...................................... 2,441 2,167 1,832 ====== ====== ====== </TABLE> F - 24
BP AMOCO p.l.c. AND SUBSIDIARIES 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, 1999..................... 3,601 139 338 4,078 Exchange adjustments................... (14) (9) (3) (26) Acquisitions........................... -- 20 3 23 Additions.............................. 757 6 181 944 Transfers.............................. (118) -- -- (118) Deletions.............................. (446) (5) (12) (463) ----------- ----------- ----------- ----------- At December 31, 1999................... 3,780 151 507 4,438 =========== =========== =========== =========== Depreciation At January 1, 1999..................... 715 79 247 1,041 Exchange adjustments................... (7) (4) (3) (14) Charge for the year.................... 304 6 44 354 Transfers.............................. (23) -- -- (23) Deletions.............................. (261) (1) (2) (264) ----------- ----------- ----------- ----------- At December 31, 1999................... 728 80 286 1,094 =========== =========== =========== =========== Net book amount At December 31, 1999................... 3,052 71 221 3,344 At December 31, 1998................... 2,886 60 91 3,037 =========== =========== =========== =========== </TABLE> F - 25
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 20 -- TANGIBLE ASSETS Property, plant and equipment: <TABLE> <CAPTION> Other of which Exploration Refining businesses Assets and and and under Production Marketing Chemicals corporate Total construction ----------- --------- --------- ---------- ------- ------------ ($ million) Cost <S> <C> <C> <C> <C> <C> <C> At January 1, 1999......... 82,776 18,455 14,178 1,810 117,219 4,145 Prior year adjustment - change in accounting policy..... 1,823 -- -- -- 1,823 -- ----------- --------- --------- ---------- ------- ------------ Restated................... 84,599 18,455 14,178 1,810 119,042 4,145 Exchange adjustments....... (972) 75 (436) (16) (1,349) (21) Acquisitions............... -- 10 1 108 119 53 Additions.................. 2,964 871 1,078 140 5,053 1,531 Transfers.................. 355 (5) -- -- 350 (2,605) Deletions.................. (3,215) (735) (714) (406) (5,070) (74) ----------- --------- --------- ---------- ------- ------------ At December 31, 1999....... 83,731 18,671 14,107 1,636 118,145 3,029 =========== ========= ========= ========== ======= ============ Depreciation At January 1, 1999......... 46,648 8,744 6,435 927 62,754 Prior year adjustment - change in accounting policy..... 1,408 -- -- -- 1,408 ----------- --------- --------- ---------- ------- Restated................... 48,056 8,744 6,435 927 64,162 Exchange adjustments....... (691) 30 (189) (7) (857) Charge for the year........ 3,401 799 534 182 4,916 Transfers.................. 23 -- -- -- 23 Deletions.................. (1,532) (457) (453) (288) (2,730) ----------- --------- --------- ---------- ------- At December 31, 1999....... 49,257 9,116 6,327 814 65,514 =========== ========= ========= ========== ======= Net book amount At December 31, 1999....... 34,474 9,555 7,780 822 52,631 3,029 At December 31, 1998....... 36,543 9,711 7,743 883 54,880 4,145 =========== ========= ========= ========== ======= ============ </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) <S> <C> <C> <C> <C> <C> <C> At December 31, 1999....... 1,741 969 772 2,554 1,321 1,233 At December 31, 1998....... 1,887 918 969 2,843 1,661 1,182 ====== ============= ==== ===== ============ ===== </TABLE> <TABLE> <CAPTION> Leasehold land --------------------- Over 50 years Freehold land unexpired Other ------------- ------------- ----- ($ million) <S> <C> <C> <C> At December 31, 1999.................................. 942 47 38 At December 31, 1998.................................. 963 42 29 ============= ============= ===== </TABLE> F - 26
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 21 -- FIXED ASSETS -- INVESTMENTS <TABLE> <CAPTION> Associated undertakings ------------------------ Share of retained Joint Own Other Shares Loans profit ventures Loans shares(a) investments(b) Total ------ ----- -------- -------- ----- ------ ----------- ------ ($ million) Cost <S> <C> <C> <C> <C> <C> <C> <C> <C> At January 1, 1999.... 2,759 835 783 5,005 80 489 51 10,002 Exchange adjustments.. (6) (11) (49) (395) (1) (16) (1) (479) Additions and net movements in joint ventures... 147 63 110 843 85 77 1 1,326 Acquisitions.......... 6 -- -- -- -- -- 3 9 Transfers............. 14 3 -- (249) -- -- -- (232) Deletions............. (54) (8) 19 -- (68) (94) (3) (208) ------ ----- -------- -------- ----- ------ ----------- ------ At December 31, 1999.. 2,866 882 863 5,204 96 456 51 10,418 ====== ===== ======== ======== ===== ====== =========== ====== Amounts provided At January 1, 1999.... 215 -- -- -- 14 -- 1 230 Exchange adjustments.. (2) -- -- -- -- -- -- (2) Provided in the year.. 64 -- -- -- 19 -- -- 83 Transfers............. -- -- -- -- -- -- -- -- Deletions............. -- -- -- -- (2) -- -- (2) ------ ----- -------- -------- ----- ------ ----------- ------ At December 31, 1999. 277 -- -- -- 31 -- 1 309 ====== ===== ======== ======== ===== ====== =========== ====== Net book amount At December 31, 1999.. 2,589 882 863 5,204 65 456 50 10,109 At December 31, 1998.. 2,544 835 783 5,005 66 489 50 9,772 ====== ===== ======== ======== ===== ====== =========== ====== </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, 1999 the ESOPs held 53,989,000 (62,768,000 at December 31, 1998) shares for the Employee Share Schemes and 9,502,000 (6,266,000 at December 31, 1998) shares for the Long Term Performance Plan. The market value of these shares at December 31, 1999 was $640 million ($517 million at December 31, 1998). (b) Other investments are unlisted. NOTE 22 -- INVENTORIES <TABLE> <CAPTION> December 31, -------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Petroleum................................................... 3,517 1,896 Chemicals................................................... 828 917 Other....................................................... 202 174 ------ ------ 4,547 2,987 Stores...................................................... 577 655 ------ ------ 5,124 3,642 ====== ====== Replacement cost............................................ 5,165 3,747 ====== ====== </TABLE> F - 27
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 23 -- RECEIVABLES <TABLE> <CAPTION> December 31, 1999 December 31, 1998 ----------------- ----------------- Within After Within After 1 year 1 year 1 year 1 year ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Trade receivables.................................. 9,417 -- 5,778 -- ====== ====== ====== ====== Other receivables: Joint ventures................................... 725 -- 644 -- Associated undertakings.......................... 60 45 153 7 Prepayments and accrued income................... 1,229 459 786 509 Taxation recoverable............................. 263 83 248 165 Pension prepayment............................... -- 2,542 -- 2,213 Other............................................ 1,653 326 1,795 411 ------ ------ ------ ------ 3,930 3,455 3,626 3,305 ====== ====== ====== ====== </TABLE> Provisions for doubtful debts deducted from Trade receivables amounted to $117 million ($126 million at December 31, 1998). - ---------- See Note 44 -- US generally accepted accounting principles. NOTE 24 -- CURRENT ASSETS -- INVESTMENTS <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Publicly traded -- United Kingdom...................................... 56 48 -- Foreign............................................. 42 33 ------ ------ 98 81 Not publicly traded................................................... 122 389 ------ ------ 220 470 ====== ====== Stock exchange value of publicly traded investments................... 99 83 ====== ====== </TABLE> NOTE 25 -- FINANCE DEBT <TABLE> <CAPTION> December 31, 1999 December 31, 1998 ----------------- ----------------- Within After Within After 1 year 1 year 1 year 1 year ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Bank loans and overdrafts.......................... 264(a) 726 302(a) 1,778 Other loans........................................ 4,548(a) 7,181 3,711(a) 6,080 ------ ------ ------ ------ Total borrowings................................... 4,812 7,907 4,013 7,858 Obligations under capital leases................... 88 1,737 101 1,783 ------ ------ ------ ------ 4,900 9,644 4,114 9,641 ====== ====== ====== ====== </TABLE> - --------------- (a) Amounts due within one year include current maturities of long-term debt. F - 28
BP AMOCO p.l.c. AND SUBSIDIARIES 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 $91 million ($86 million at December 31, 1998) 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 $1,376 million (December 31, 1998 $1,277 million) with maturity periods ranging up to 35 years. They are classified as repayable within one year, as required under UK GAAP, as the bondholders typically have the option to tender these bonds for repayment on interest reset dates. Any bonds that are tendered are usually remarketed and BP Amoco has not experienced any significant repurchases. BP Amoco considers these bonds to represent long-term funding when assessing the maturity profile of its borrowings. ANALYSIS OF BORROWINGS BY YEAR OF REPAYMENT <TABLE> <CAPTION> December 31, 1999 December 31, 1998 ------------------------------- ------------------------------ Bank loans Bank loans and Other and Other overdrafts loans Total overdrafts loans Total --------- --------- --------- ---------- -------- --------- ($ million) <S> <C> <C> <C> <C> <C> <C> Due after 10 years........ 110 1,290 1,400 11 1,391 1,402 Due within 6-10 years...... 45 1,816 1,861 266 1,825 2,091 5 years......... 410 722 1,132 201 365 566 4 years......... 36 377 413 785 1,081 1,866 3 years......... 87 1,774 1,861 288 652 940 2 years......... 38 1,202 1,240 227 766 993 --------- --------- --------- ---------- -------- --------- 726 7,181 7,907 1,778 6,080 7,858 1 year.......... 264 4,548 4,812 302 3,711 4,013 --------- --------- --------- ---------- -------- --------- 990 11,729 12,719 2,080 9,791 11,871 ========= ========= ========= ========== ======== ========= </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, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> After five years............................................ 46 174 Within five years........................................... 91 406 ------ ------ 137 580 ====== ====== </TABLE> Interest rates on borrowings repayable wholly or partly more than five years from December 31, 1999 range from 6% to 9% with a weighted average of 7%. The weighted average interest rate on finance debt is 6%. At December 31, 1999 the Group had substantial amounts of undrawn borrowing facilities available, including $3,000 million ($2,800 million at December 31, 1998) expiring in 2000. These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates. Certain of these facilities support the Group's commercial paper programme. F - 29
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 25 -- FINANCE DEBT (CONTINUED) ANALYSIS OF BORROWINGS BY CURRENCY <TABLE> <CAPTION> December 31, December 31, 1999 1998 ----------------------------------------------------------------- ----------- Fixed rate debt Floating rate debt --------------------------------- ------------------- Weighted Weighted Weighted average average time average interest for which interest rate rate is fixed Amount rate Amount Total Total -------- ------------- ------ -------- ------ ----- ----- (%) (Years) ($ million) (%) ($ million)($ million) ($ million) <S> <C> <C> <C> <C> <C> <C> <C> US dollars................. 7 9 6,529 6 5,915 12,444 10,852 Sterling................... -- -- -- 6 49 49 613 Other currencies........... 8 31 46 6 180 226 406 ------ -------- ------- ------- Total loans................ 6,575 6,144 12,719 11,871 ====== ======== ======= ======= </TABLE> The Group aims for a balance between floating and fixed interest rates and, in 1999, 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, 2000 would change 2000 profit before tax by approximately $80 million. FAIR VALUES AND CARRYING AMOUNTS OF BORROWINGS <TABLE> <CAPTION> December 31, ---------------------------------------------- 1999 1998 ---------------------- ---------------------- Carrying Carrying Fair value amount Fair value amount ---------- -------- ---------- -------- ($ million) <S> <C> <C> <C> <C> Short-term borrowings.................... 2,433 2,433 1,659 1,659 Long-term borrowings..................... 9,979 10,118 10,555 10,126 ---------- -------- ---------- -------- Total borrowings......................... 12,412 12,551 12,214 11,785 ========== ======== ========== ======== </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, 1999, 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 - 30
BP AMOCO p.l.c. AND SUBSIDIARIES 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, 1999 ----------- ($ million) <S> <C> 2000 ............................................................... 103 2001 ............................................................... 192 2002 ............................................................... 183 2003 ............................................................... 172 2004 ............................................................... 178 Thereafter........................................................... 3,569 ----------- 4,397 Less: amount representing lease interest............................. 2,572 ----------- Present value of net minimum capital lease payments.................. 1,825 =========== of which -- due within one year...................................... 88 -- due after one year....................................... 1,737 ----------- </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, 1999 1999 1998 ----------------- ------ ------ (%) ($ million) <S> <C> <C> <C> Sterling.................................. 6 40 486 US dollars................................ 8 7,786 7,180 Other currencies.......................... 10 81 192 ------ ------ 7,907 7,858 ====== ====== </TABLE> Bank loans and overdrafts and other loans -- short term <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Current maturities of long-term debt........................ 1,003 1,077 Commercial paper............................................ 2,201 1,333 Bank loans and overdrafts................................... 232 300 Other....................................................... 1,376 1,303 ------ ------ 4,812 4,013 ====== ====== </TABLE> F - 31
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 25 -- FINANCE DEBT (CONCLUDED) <TABLE> <CAPTION> Weighted average interest rate at December 31, ---------------- 1999 1998 ------ ------ (%) <S> <C> <C> Commercial paper............................................ 6 5 Bank loans, overdrafts and other borrowings................. 6 7 US Industrial Revenue/Municipal bonds....................... 5 4 </TABLE> NOTE 26 -- ACCOUNTS PAYABLE AND ACCRUED LIABILITIES <TABLE> <CAPTION> December 31, 1999 December 31, 1998 ----------------- ----------------- Within After Within After 1 year 1 year 1 year 1 year ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Trade payables....................................... 8,203 -- 5,091 -- ====== ====== ====== ====== Other accounts payable and accrued liabilities: Joint ventures..................................... 278 -- 205 -- Associated undertakings............................ 199 4 154 4 Production taxes................................... 417 1,140 241 1,238 Taxation on profits................................ 2,558 39 2,395 39 Social security.................................... 14 -- 14 -- Accruals and deferred income....................... 3,610 618 2,642 454 Dividends.......................................... 971 -- 1,552 -- Other.............................................. 2,125 444 3,035 312 ------ ------ ------ ------ 10,172 2,245 10,238 2,047 ====== ====== ====== ====== </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, 1999...... 3,310 1,157 1,767 2,311 272 8,817 Prior year adjusted - change in accounting policy (Note 43) (229) (172) -- -- 163 (238) --------------- ------------- ------- -------------- ----- ----- Restated................ 3,081 985 1,767 2,311 435 8,579 Exchange adjustments.... (57) (4) (224) -- (5) (290) New provisions.......... 80 145 160 42 500 927 Unwinding of discount... 94 25 -- -- 11 130 Change in discount rate. (280) (18) -- -- (2) (300) Utilized/deleted........ (133) (216) (108) (109) (208) (774) --------------- ------------- ------- -------------- ----- ----- At December 31, 1999.... 2,785 917 1,595 2,244 731 8,272 =============== ============= ======= ============== ===== ===== </TABLE> F - 32
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 27 -- OTHER PROVISIONS (CONCLUDED) At December 31, 1999 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 $2,785 million. 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% (3%). The provision for environmental liabilities at 31 December 1999 was $917 million. 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% (3%). 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% (3%). 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 9 -- Management's Discussion and Analysis of Financial Condition and Results of Operations and in Item 9A -- 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 - 33
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 28 -- DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED) With the exception of the table of currency exposures shown on page F-36, 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 FRS13. INTEREST RATE RISK The interest rate and currency profile of the financial liabilities of the Group at December 31, 1999, 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 average time Weighted average time ANALYSIS OF FINANCIAL average for which average until LIABILITIES BY CURRENCY interest rate rate is fixed Amount interest Amount maturity Amount Total ------------- ------------- ------ -------- ------ ------------ ------ ------ (%) (Years) ($m) (%) ($m) (Years) ($m) ($m) <S> <C> <C> <C> <C> <C> <C> <C> <C> 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 ====== ====== ====== ====== Analysis of the above liabilities by balance sheet caption: Creditors-- amounts falling due within one year - --Finance debt................................................................................. 4,900 Creditors-- amounts falling due after more than one year - --Finance debt................................................................................. 9,644 - --Other creditors.............................................................................. 1,062 Provisions for liabilities and charges - --Other provisions............................................................................. 408 ------ 16,014 ====== </TABLE> 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 1999, 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 as at December 31, 1999. <TABLE> <CAPTION> $ million except percentages ------------------ <S> <C> Receive fixed rate swaps-- notional amount.................................. 2,300 Average receive fixed rate ................................................. 6.3% Average pay floating rate................................................... 5.9% Pay fixed rate swaps-- notional amount...................................... 3,221 Average pay fixed rate...................................................... 7.1% Average receive floating rate............................................... 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. F - 34
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 28 -- DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED) The following table shows the interest rate and currency profile of the Group's material financial assets at December 31, 1999. <TABLE> <CAPTION> December 31, 1999 ------------------------------------------------------------------------------------- Fixed rate Floating rate Interest free ------------------------------------ ----------------- --------------------- Weighted Weighted Weighted average time Weighted average time ANALYSIS OF FINANCIAL average for which average until ASSETS BY CURRENCY interest rate rate is fixed Amount interest Amount maturity Amount Total ------------- ------------- ------ -------- ------ ------------ ------ ------ (%) (Years) ($m) (%) ($m) (Years) ($m) ($m) <S> <C> <C> <C> <C> <C> <C> <C> <C> US dollars............. 5 1 12 5 748 3 122 882 Sterling............... 9 2 55 -- -- 1 357 412 Other currencies....... 6 1 44 3 168 2 371 583 ------ ------ ------ ------ 111 916 850 1,877 ====== ====== ====== ====== Analysis of the above assets by balance sheet caption: Current assets - --Debtors -- amounts falling due after more than one year.................................... 326 - --Investments................................................................................ 220 - --Cash at bank and in hand................................................................... 1,331 ------ 1,877 ====== </TABLE> The floating rate financial assets earn interest at various rates set principally with respect to LIBOR or the local market equivalent. MATURITY PROFILE OF FINANCIAL LIABILITIES The profile of the maturity of the financial liabilities included in the Group's balance sheet at December 31,1999 is shown in the table below. <TABLE> <CAPTION> December 31, 1999 CARRYING AMOUNT OF FINANCIAL LIABILITIES ----------------- ($ million) <S> <C> Due within: 1 year............................................................ 4,900 1 to 2 years...................................................... 1,505 2 to 5 years...................................................... 3,845 Thereafter........................................................ 5,764 ------- 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, 1999, these exposures were as shown below. F - 35
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 28 -- DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED) FUNCTIONAL CURRENCY OF GROUP OPERATION <TABLE> <CAPTION> December 31, 1999 ------------------------------------------------- Net foreign currency monetary assets (liabilities) ------------------------------------------------- US dollar Sterling Euro Other Total --------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> 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. 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 finance debt. <TABLE> <CAPTION> December 31, 1999 ------------------------------------- Net carrying Net fair value amount asset (liability) asset(liability) ---------------- --------------- ($ million) <S> <C> <C> PRIMARY FINANCIAL INSTRUMENTS Current assets - --Debtors-- amounts falling due after more than one year.... 326 326 - --Investments............................................... 221 220 - --Cash at bank and in hand.................................. 1,331 1,331 Finance debt - --Short-term borrowings..................................... (2,433) (2,433) - --Long-term borrowings...................................... (9,979) (10,118) - --Net obligations under finance leases...................... (1,824) (1,802) Creditors-- amounts falling due after more than one year - --Other creditors........................................... (1,062) (1,062) Provisions for liabilities and charges-- Other provisions... (408) (408) DERIVATIVE FINANCIAL OR COMMODITY INSTRUMENTS Risk management-- interest rate contracts.................. 37 -- -- foreign exchange contracts............... (209) (191) -- oil price contracts...................... -- -- -- natural gas price contracts.............. 2 -- Trading -- interest rate contracts.................. -- -- -- foreign exchange contracts............... -- -- -- oil price contracts...................... (61) (61) </TABLE> F - 36
BP AMOCO p.l.c. AND SUBSIDIARIES 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: 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 - 37
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 28 -- DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED) <TABLE> <CAPTION> Year ended December 31, 1999 --------------------------------------------------------------- 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, 1999........... 253 (402) (149) 143 (194) (51) of which accounted for in income in 1999.... 115 (95) 20 58 (66) (8) Gains and losses at December 31, 1999......... 236 (215) 21 65 (283) (218) of which expected to be recognized in income: In 2000..................................... 53 (58) (5) 32 (45) (13) In 2001 or later............................ 183 (157) 26 33 (238) (205) </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, ---------------------------------------------------------------- 1999 1998 --------------------------------------------- ---------------- Year end Year end Average Average fair value fair value net fair value net fair value asset liability asset (liability) asset (liability) ---------- ---------- ---------------- ---------------- ($ million) <S> <C> <C> <C> <C> Interest rate contracts....... -- -- -- (8) Foreign exchange contracts.... 4 (4) -- 21 Oil price contracts........... 155 (216) 54 60 ---------- ---------- ---------------- ---------------- 159 (220) 54 73 ========== ========== ================ ================ </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 - 38
BP AMOCO p.l.c. AND SUBSIDIARIES 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, ------------------------------------------------------ 1999 1998 ----------------------------------- ----------------- High Low Average Year end Average Year end ------- ------- ------- -------- ------- -------- ($ million) <S> <C> <C> <C> <C> <C> <C> Interest rate contracts................ 1 -- 1 -- 2 -- Foreign exchange contracts............. 13 -- 3 1 4 -- Oil price contracts.................... 15 5 9 10 8 12 </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, ---------------------- 1999 1998 -------- -------- Net gain Net gain (loss) (loss) -------- -------- ($ million) <S> <C> <C> Oil price derivative financial and commodity instruments............. 133 540 Physical oil trades.................................................. 151 (325) -------- -------- Total oil trading.................................................... 284 215 Interest rate contracts.............................................. -- (26) Foreign exchange contracts........................................... 23 38 -------- -------- 307 227 ======== ======== </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 - 39
BP AMOCO p.l.c. AND SUBSIDIARIES 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 six 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 Amoco meets initial margin requirements by bank guarantees and daily margin calls in cash. For swaps and over-the-counter options, BP Amoco 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 - 40
BP AMOCO p.l.c. AND SUBSIDIARIES 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, ---------------------------------------------- 1999 1998 ---------------------- ---------------------- Carrying Fair Carrying Fair amount value amount value --------- --------- --------- --------- ($ million) <S> <C> <C> <C> <C> Finance debt Long-term............................... 10,118 9,979 10,126 10,555 Short-term.............................. 2,433 2,433 1,659 1,659 Cash at bank and in hand.................. 1,331 1,331 405 405 </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 $458 million ($436 million at December 31, 1998). The credit risk and maximum cash requirement of these guarantees and indemnities is the full contractual amount, however no material loss is expected to arise. The following information is presented in compliance with the requirements of FASB Statement of Accounting Standards No.105 -- `Disclosure of Information about Financial Instruments with Off-Balance-Sheet Risk and Financial Instruments with Concentrations of Credit Risk'. The table shows the 'fair value' of the asset or liability created by derivatives. This represents the market value at the balance sheet date. Credit exposure at December 31 is represented by the column 'fair value asset'. The table also shows the 'net carrying amount' of the asset or liability created by derivatives. This amount represents the net book value, i.e. market value when acquired or later marked to market. F - 41
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 28 -- DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED) <TABLE> <CAPTION> Gross Net carrying contract Fair value Fair value amount asset amount asset (liability) (liability) --------- ---------- ---------- ------------ ($ million) <S> <C> <C> <C> <C> AT DECEMBER 31, 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 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) AT DECEMBER 31, 1998 Risk management Interest rate contracts........ 5,866 69 (328) (45) Foreign exchange contracts..... 8,908 181 (160) (75) Oil price contracts............ 491 12 (5) 7 Natural gas contracts.......... 1,511 51 (44) -- Trading Interest rate contracts........ 189 -- -- -- Foreign exchange contracts..... 9,441 30 (39) (9) Oil price contracts............ 4,038 134 (123) 11 </TABLE> Interest rate contracts include forward and 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, 1999 December 31, 1998 ----------------------------- ----------------------------- 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 ....................... 5,521 138 (101) 5,866 69 (328) ======= ======= ======= ======= ======= ======= </TABLE> Interest rate swaps allow BP Amoco 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 - 42
BP AMOCO p.l.c. AND SUBSIDIARIES 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, --------------------------------- 1999 1998 ------------- ------------- ($ million, except percentages) <S> <C> <C> Receive-- fixed swaps-- notional amount............ 2,300 2,125 Average receive fixed rate......................... 6.3% 6.6% Average pay floating rate.......................... 5.9% 5.4% Pay-- fixed swaps-- notional amount................ 3,221 3,741 Average pay fixed rate............................. 7.1% 7.3% Average receive floating rate...................... 6.0% 5.3% </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 holds 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, 1999 December 31, 1998 ------------------------------- ------------------------------ 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............... 2,109 30 (200) 1,797 99 (107) Forwards..................... 2,237 6 (44) 4,046 63 (38) Options...................... 680 3 (4) 3,065 19 (15) --------- --------- --------- --------- --------- --------- 5,026 39 (248) 8,908 181 (160) ========= ========= ========= ========= ========= ========= </TABLE> F - 43
BP AMOCO p.l.c. AND SUBSIDIARIES 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 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 six years. The majority of the Group's currency swaps relate to major currencies such as Sterling, Deutschmarks, Swiss Francs 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. The Group's forward contracts are generally settled over periods of up to one year. 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. 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 Amoco 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, 1999 December 31, 1998 ------------------------------- ------------------------------ 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................. 361 8 (13) 421 12 (5) Futures............... 143 5 -- 70 -- -- --------- --------- --------- --------- --------- --------- 504 13 (13) 491 12 (5) ========= ========= ========= ========= ========= ========= Natural gas Swaps................. 4,346 55 (52) 1,478 48 (43) Options............... 7 -- -- 33 3 (1) Futures............... 42 1 (2) -- -- -- --------- --------- --------- --------- --------- --------- 4,395 56 (54) 1,511 51 (44) ========= ========= ========= ========= ========= ========= </TABLE> F - 44
BP AMOCO p.l.c. AND SUBSIDIARIES 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 Amoco 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, 1999 and 1998 and the average fair value for the year. <TABLE> <CAPTION> Year ended December 31, 1999 Year ended December 31, 1998 ------------------------------- --------------------------------- 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 -- -- 185 -- (1) Options..................... -- -- -- 4 -- -- Swaptions................... -- -- -- -- -- (7) --------- --------- --------- --------- --------- --------- 200 -- -- 189 -- (8) ========= ========= ========= ========= ========= ========= Foreign exchange contracts Forwards.................... 1,549 -- -- 3,012 (9) 23 Options..................... 125 -- -- 6,429 -- (2) --------- --------- --------- --------- --------- --------- 1,674 -- -- 9,441 (9) 21 ========= ========= ========= ========= ========= ========= Oil price contracts Swaps....................... 2,372 (63) 62 3,460 11 54 Futures..................... 470 -- -- 413 -- -- Options..................... 302 4 6 165 -- -- --------- --------- --------- --------- --------- --------- 3,144 (59) 68 4,038 11 54 ========= ========= ========= ========= ========= ========= </TABLE> F - 45
BP AMOCO p.l.c. AND SUBSIDIARIES 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, 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 a quality equal to or better than BP Amoco's when agreed. The credit quality is actively managed over the life of the swap. NOTE 29 -- CAPITAL AND RESERVES <TABLE> <CAPTION> Paid Share in Merger Retained capital surplus reserve earnings Total --------- --------- --------- --------- --------- ($ million) <S> <C> <C> <C> <C> <C> At January 1, 1999..................... 4,863 3,386 697 32,840 41,786 Prior year adjustment - change in accounting policy (Note 43).......... -- -- -- 715 715 --------- --------- --------- --------- --------- Restated............................... 4,863 3,386 697 33,555 42,501 Employee share schemes................. 16 311 -- (61) 266 Share dividend plan.................... 13 (13) -- 311 311 Profit for the year.................... -- -- -- 5,008 5,008 Dividends.............................. -- -- -- (3,884) (3,884) Exchange adjustment.................... -- -- -- (921) (921) --------- --------- --------- --------- --------- At December 31, 1999................... 4,892 3,684 697 34,008 43,281 ========= ========= ========= ========= ========= </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 Amoco shares issued or repurchased. EMPLOYEE SHARE SCHEMES. During the year 66,162,232 ordinary shares were issued under employee share schemes. Certain of these shares were issued via a QUEST. See Note 33 for further details. SHARE DIVIDEND PLAN. 51,842,146 ordinary shares were issued under the share dividend plan by capitalization of the paid in surplus. F - 46
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 30 -- RETAINED EARNINGS Retained earnings of $34,008 million ($33,555 million at December 31, 1998) include the following amounts, the distribution of which is limited by statutory or other restrictions: <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Parent company....................................................... 16 16 Subsidiary undertakings.............................................. 5,638 5,195 Associated undertakings.............................................. 1,649 1,162 ------ ------ 7,303 6,373 ====== ====== </TABLE> Cumulative net exchange losses of $1,374 million are included in retained earnings ($453 million losses at December 31, 1998). There were no unrealized currency translation differences for the year on long-term borrowings used to finance equity investments in foreign currencies (1998 nil and 1997 unrealized losses of $2 million). NOTE 31 -- ANALYSIS OF CONSOLIDATED STATEMENT OF CASH FLOWS (I) RECONCILIATION OF HISTORICAL COST PROFIT BEFORE INTEREST AND TAX TO NET CASH INFLOW FROM OPERATING ACTIVITIES <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Historical cost profit before interest and tax........... 8,342 5,980 9,872 Depreciation and amounts provided........................ 4,965 5,301 5,117 Exploration expenditure written off...................... 304 373 365 Share of (profits) losses of joint ventures and associated undertakings............................ (1,704) (1,102) (777) Interest and other income................................ (217) (272) (255) (Profit) loss on sale of businesses and fixed assets..... 379 (963) (563) Charge for provisions.................................... 847 377 421 Utilization of provisions................................ (597) (460) (401) Decrease (increase) in inventories....................... (1,562) 584 1,740 Decrease (increase) in debtors........................... (4,013) 1,768 2,033 (Decrease) increase in payables.......................... 3,546 (2,000) (1,994) ------ ------ ------ Net cash inflow from operating activities................ 10,290 9,586 15,558 ====== ====== ====== </TABLE> (II) EXCEPTIONAL ITEMS The cash outflow in respect of the restructuring costs charged in 1999 was $976 million. The cash outflow relating to the merger expenses charged in 1998 was $166 million (1998 $32 million). Both amounts were included in the net cash inflow from operating activities. F - 47
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 31-- ANALYSIS OF CONSOLIDATED STATEMENT OF CASH FLOWS (CONCLUDED) (III) FINANCING <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Long-term borrowing.................................. (2,140) (2,078) (1,179) Repayments of long-term borrowing.................... 2,268 1,208 884 Short-term borrowing................................. (3,136) (631) (1,285) Repayments of short-term borrowing................... 2,299 701 1,342 ----- ------ ------ (709) (800) (238) Issue of ordinary share capital...................... (245) (161) (172) Repurchase of share capital.......................... -- 584 1,422 ----- ------ ------ Net cash (inflow) outflow............................ (954) (377) 1,012 ===== ====== ====== </TABLE> (IV) MANAGEMENT OF LIQUID RESOURCES Liquid resources comprise current asset investments which are principally commercial paper issued by other companies. The net cash inflow from the management of liquid resources was $93 million (1998 $596 million and 1997 $167 million). (V) COMMERCIAL PAPER Net movements in commercial paper are included within short-term borrowings or repayment of short-term borrowings as appropriate. (VI) MOVEMENT IN NET DEBT <TABLE> <CAPTION> Years ended December 31, ------------------------------------------------------------------------------ 1999 1998 -------------------------------------- -------------------------------------- Current Current Finance asset Net Finance asset Net debt Cash investments debt debt Cash investments debt ------- ------- ----------- ------- ------- ------- ----------- ------- ($ million) <S> <C> <C> <C> <C> <C> <C> <C> <C> At January 1.... (13,755) 405 470 (12,880) (12,877) 355 1,067 (11,455) Net cash flow... (709) 965 (93) 163 (800) 67 (596) (1,329) Other movements. (67) -- (150) (217) (53) -- -- (53) Exchange adjustments (13) (39) (7) (59) (25) (17) (1) (43) ------- ------- ----------- ------- ------- ------- ----------- ------- At December 31.. (14,544) 1,331 220 (12,993) (13,755) 405 470 (12,880) ======= ======= =========== ======= ======= ======= =========== ======= </TABLE> F - 48
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 32 -- OPERATING LEASE COMMITMENTS Annual commitments under operating leases were as follows: <TABLE> <CAPTION> December 31, ----------------------------------------------- 1999 1998 ----------------------------------------------- Land and Land and buildings Other buildings Other --------- --------- --------- --------- ($ million) <S> <C> <C> <C> <C> <C> Expiring within: 1 year 19 107 50 149 2 to 5 years............ 57 372 92 432 Thereafter.............. 163 250 174 99 --------- --------- --------- --------- 239 729 316 680 ========= ========= ========= ========= </TABLE> The minimum future lease payments (after deducting related rental income from operating sub-leases of $518 million) were as follows: <TABLE> <CAPTION> December 31, 1999 ----------- ($million) <S> <C> 2000 ............................................................... 924 2001 ............................................................... 801 2002 ............................................................... 736 2003 ............................................................... 556 2004 ............................................................... 504 Thereafter........................................................... 1,898 ----------- 5,419 =========== </TABLE> F - 49
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 33 -- EMPLOYEE SHARE SCHEMES BP Amoco offers most of its employees the opportunity to acquire a shareholding in the Company through savings related and matching arrangements (participating share schemes and savings plans). BP Amoco also uses a long-term performance plan (see Note 34) and the granting of share options as elements of employee remuneration. Under the UK Savings Related Share Option Scheme employee save monthly over a three-or-five year period toward 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. Similar schemes are run in a number of overseas countries. Under the UK Participating Scheme, BP Amoco 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. There are similar schemes in a number of overseas countries. The Company sponsors a number of savings plans covering most US employees. Under these plans, employees may contribute up to 20% of their salary subject to certain regulatory limits. BP Amoco matches employee contributions up to 7%, depending upon length of service. The plans invest primarily in BP Amoco ADSs. The Company's contributions vest over a period of five years. Company contributions to savings plans during the year were $95 million (1998 $91 million). During 1999, BP Amoco granted options under the BP Amoco Share Option Plan to certain categories of employees. Prior to 1999, BP and Amoco granted options under the BP Executive Share Option Scheme (BP ESOS) and the Amoco Stock Option Plan respectively. Options were granted to former 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 Stock Option Plan. Options were also granted to certain former 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 1999, options were granted to non-US middle managers in prior years these were granted under the BP ESOS. 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 Remuneration Committee will require the total return to shareholders (share price increase with all dividends reinvested) on an investment in BP Amoco shares to exceed the mean total return to shareholders of a representative group of UK companies by a margin set from time to time by the committee. 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. An Employee Share Ownership Plan (ESOP) has been established to acquire BP Amoco shares to satisfy future requirements of certain employee share schemes. Funding is provided to the ESOP by the Company. 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 1999 the ESOP released 8,779,000 shares for the participating share schemes. The cost of shares released for these schemes has been charged in these accounts. At December 31, 1999 the ESOP held 53,989,000 shares (December 31, 1998, 62,768,000). F - 50
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 33 -- EMPLOYEE SHARE SCHEMES (CONTINUED) BP Amoco has established a Qualifying Employee Share Ownership Trust (QUEST) for the purposes of share option schemes for UK employees and executive directors of the company and its subsidiaries. During the year, contributions of $61 million ($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 cost of this contribution has been transferred by the Company directly to retained profits and the excess of the subscription price over nominal value has increased the share premium account. At December 31, 1999, all the 9,672,542 ordinary shares issued to the QUEST had been transferred to option holders exercising options under the UK Group Savings Related Share Option Scheme. <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ (Options thousands) <S> <C> <C> <C> Employee share options granted during the year: BP Amoco savings related and similar schemes....... 8,828 9,734 14,778 BP Amoco share option plan......................... 41,054 -- -- BP ESOS............................................ -- 2,576 4,538 Amoco Stock Option Plan............................ -- 60,696 53,982 ------ ------ ------ 49,882 73,006 73,298 ====== ====== ====== </TABLE> The exercise prices for BP options granted during the year were L4.495/$7.28 (8,828,566 options) for savings-related and similar schemes and L5.02/$8.01 (weighted average price) for 41,053,562 options granted under the share option plan. <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ (Shares thousands) <S> <C> <C> <C> Shares issued in respect of options exercised during the year: BP Amoco savings related and similar schemes........ 12,176 12,582 27,948 BP ESOS............................................. 7,861 10,260 8,804 Amoco Stock Option Plan............................. 43,611 30,634 28,394 ------ ------ ------ 63,648 53,476 65,146 ====== ====== ====== </TABLE> In addition 2,514,000 shares (1998, 3,298,000 shares and 1997, 13,644,000 shares) were issued, and 8,779,000 shares (1998, 8,518,000 shares and 1997 nil) released from the ESOP for participating share schemes. <TABLE> <CAPTION> 1999 1998 1997 ------ ------ ------ <S> <C> <C> <C> Options outstanding at December 31: BP Amoco options (shares thousands).................. 323,161 346,898 336,066 Exercise period..................................... 2000-2009 1999-2008 1998-2007 Price............................................... $2.09-$10.1 $1.85-$7.88 $1.85-$5.97 </TABLE> F - 51
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 33 -- EMPLOYEE SHARE SCHEMES (CONTINUED) Share option transactions under employee share schemes are summarized as follows: <TABLE> <CAPTION> Years ended December 31, ---------------------------------------------------------------------- 1999 1998 1997 -------------------- --------------------- ------------------- Weighted Weighted Weighted average average average Number of exercise Number of exercise Number of exercise shares price shares price shares price --------- -------- --------- -------- --------- -------- ($) ($) ($) <S> <C> <C> <C> <C> <C> <C> Outstanding at January 1... 346,897,822 4.34 336,066,100 3.85 336,891,588 3.25 Reinstated................. 37,480 5.24 33,486 2.82 1,920 3.72 Granted.................... 49,882,128 7.88 73,005,560 5.64 373,298,654 5.47 Exercised.................. (63,711,433) 3.85 (53,475,492) 3.00 (65,145,366) 2.59 Stock appreciation rights exercised................ (542,772) 3.30 (698,720) 2.56 (635,200) 2.40 Cancelled.................. (9,401,838) 5.54 (8,033,112) 4.73 (8,345,496) 3.68 ----------- ----------- ---------- Outstanding at December 31. 323,161,387 4.95 346,897,822 4.34 336,066,100 3.85 =========== =========== =========== Exercisable at December 31. 206,116,577 202,132,716 188,210,596 =========== =========== =========== Available for grant at December 31.............. 1,087,626,398 1,177,618,184 493,888,856 ============= ============= =========== </TABLE> Options outstanding at December 31, 1999 will be exercisable between 2000 and 2009. Available for grant figures for 1997 are as previously reported for BP p.l.c. For the share options outstanding and exercisable at December 31, 1998 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 $2.01 - $3.62................. 96,461,832 2.75 3.27 86,451,031 3.30 $3.72 - $4.61................. 62,721,177 5.48 4.26 57,173,680 4.31 $4.68 - $6.93................. 115,913,522 6.91 5.54 62,470,866 5.60 $7.28 - $10.10................ 48,064,916 8.36 7.88 21,000 7.89 ----------- --------- -------- ----------- -------- 323,161,387 5.61 4.96 206,116,577 4.28 =========== ========= ======== =========== ======== </TABLE> F - 52
BP AMOCO p.l.c. AND SUBSIDIARIES 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 1999 would have been reduced by $65 million (1998 $47 million and 1997 $43 million) and 1 cent (1998 1 cent and 1997 1 cent), respectively. The weighted average fair value of BP Amoco share options granted in 1999 was $2.27 (1998 $2.29 and 1997 $2.97). 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 1999, 1998 and 1997, respectively; risk-free interest rates of 6.5, 6.0 and 7.0%; dividend yield of 3%; expected lives of three to five years and volatility of 32%, 18% and 18%. In 1998 and earlier years Amoco had granted stock options. Following the merger between BPand Amoco these were converted into BPAmoco share options. The weighted average fair value of Amoco stock options granted in 1998 was $7.40 and in 1997 was $8.41. On the basis of BP Amoco shares these equate to values of $1.86 and $2.12 respectively. 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 and 1997 respectively; risk-free interest rates of 5.7 and 6.7, 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 Senior executives and the executive directors participate in the Long Term Performance Plan (the Plan). This is an incentive scheme under which the Remuneration Committee may award shares to participants or fund the purchase of shares for participants if long-term targets are met. The Plan replaced the granting of executive share options to participants, apart from those based in North America who will continue to receive share options in line with local market practice. 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 1999 was $128 million (1998 $45 million and 1997 $28 million). The value of awards under the 1996-98 Plan made in 1999 was $52 million (1995-97 Plan $36 million). Employee Share Ownership Plans (ESOPs) have been established to acquire BP Amoco shares to satisfy any awards made to particpants under the Plan and then to hold them for the participants during the retention period of the Plan. In order to hedge the cost of potential future awards the ESOPs may, from time to time over the performance period of the Plans, purchase BP Amoco shares in the open market. Funding is provided to the ESOPs by the Company. The assets and liabilities of the ESOPs are recognized as assets and liabilities of the Company within these accounts. The ESOPs have waived their rights to dividends. At December 31, 1999 the ESOPs held 9,502,000 (1998, 6,266,000) shares for potential future awards. F - 53
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 35 -- DIRECTORS' REMUNERATION <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ thousand) <S> <C> <C> <C> TOTAL FOR ALL DIRECTORS Emoluments (a)................................................. 13,309 6,870 8,264 Compensation for loss of office................................ 6,126 -- -- Gains made on the exercise of share options.................... 5,158 888 146 Amounts awarded under long-term incentive schemes.............. 7,594 4,434 6,844 ====== ====== ====== HIGHEST PAID DIRECTOR Emoluments..................................................... 2,434 1,514 1,538 Gains made on the exercise of share options.................... 4,509 806 105 Amount awarded under long-term incentive schemes............... -- 1,331 1,346 Accrued pension at December 31................................. 1,172 626 554 ====== ====== ====== </TABLE> - ---------- (a) Fees in 1998 of $45,730 and in 1997 of $60,680 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 co-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 Amoco based on actuarial advice. There were no contributions to this pension scheme in 1999, 1998 or 1997. Two executive directors participated in the Employee Retirement Plan for Amoco Corporation. NOTE 36 -- LOANS TO OFFICERS Miss J C Hanratty has a low interest loan of $43,000 made to her prior to her appointment as Company Secretary on October 1, 1994. F - 54
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 37 -- EMPLOYEE COSTS AND NUMBERS <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> EMPLOYEE COSTS Wages and salaries................................... 5,302 4,995 5,114 Social security costs................................ 359 412 388 Pension costs........................................ (97) 139 141 ------ ------ ------ 5,564 5,546 5,643 ====== ====== ====== </TABLE> <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ <S> <C> <C> <C> NUMBER OF EMPLOYEES Exploration and Production........................... 13,300 18,800 19,150 Refining and Marketing (a)........................... 45,250 52,100 53,800 Chemicals............................................ 18,700 23,050 24,000 Other businesses and corporate....................... 3,150 2,700 3,850 ------ ------ ------- 80,400 96,650 100,800 ====== ====== ======= </TABLE> <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- AVERAGE NUMBER OF EMPLOYEES <S> <C> <C> <C> <C> <C> 1999 Exploration and Production............. 3,950 900 5,300 5,600 15,750 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 ======== ======== ======== ======== ======== 1998 Exploration and Production 4,050 900 7,900 6,200 19,050 Refining and Marketing (b)............. 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 ======== ======== ======== ======== ======== 1997 Exploration and Production............. 3,750 900 8,450 5,700 18,800 Refining and Marketing................. 9,550 10,000 23,650 9,000 52,200 Chemicals.............................. 5,000 4,650 11,850 2,550 24,050 Other businesses and corporate......... 900 200 1,950 600 3,650 -------- -------- -------- -------- -------- 19,200 15,750 45,900 17,850 98,700 ======== ======== ======== ======== ======== </TABLE> - --------------- (a) Includes 18,050 (1998, 17,300 and 1997, 18,050) employees assigned to the BP/Mobil joint venture. (b) Includes 7,800 (1998, 8,550 and 1997, 7850) employees assigned to the BP/Mobil joint venture in the UK and 9,650 (1998, 9,350 and 1997, 9,600) employees in the Rest of Europe. F - 55
BP AMOCO p.l.c. AND SUBSIDIARIES 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. The main plans provide benefits that are computed based on an employee's years of service and final pensionable salary. In most cases Group companies make contributions to separately administered trusts, 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. In certain countries the plans are unfunded and the accrued liabilities for pension benefits is included within other provisions. The net credit to income for pensions in 1999 was $97 million (1998 $139 million net charge and 1997 $141 million net charge). This was assessed in accordance with independent actuarial advice using the projected unit credit method for the Group's major pension plans. The net credit for 1999 includes settlement and curtailment gains of $150 million arising from the high level of severance during the year. The principal assumptions used in calculating the credit/charge for the principle plans were as follows: <TABLE> <CAPTION> Years ended December 31, ---------------------------------------------- 1999 1998 1997 ---------- ---------- ---------- <S> <C> <C> <C> UK and other European plans: Rate of return on assets............ 6.1% 7% 8.1% Discount rate....................... 6.1% 7% 8.1% Future salary increases............. 4.3% 5.1% 5.9% Future pension increases............ 2.5% 3.2% 4.0% US plans: Rate of return on assets............ 10% 10% 10% Discount rate....................... 6.5% 6.9% 7% Future salary increases............. 4% 4.7% 4.7% Future pension increases............ nil nil nil </TABLE> At January 1, 1999 the date of the latest actuarial valuations or reviews, the market value of assets in the Group's major externally funded pension plans in the UK and the USA was $23,209 million ($20,689 million at January 1, 1998). The actuarial value of the assets of these plans represented 125% (1998 123%) of the benefits that had accrued to members of those plans, after allowing for expected future increases in salaries. At December 31, 1999 the obligation for accrued benefits in respect of the principal unfunded plans in Europe was $1,513 million ($1,714 million at December 31, 1998). Of this amount, $1,234 million ($1,345 million at December 31, 1998) has been provided in these accounts. F - 56
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 38 -- PENSIONS (CONTINUED) Further information in respect of the Group's principal defined benefit pension plans required under FASB Statement of Financial Accounting Standards No. 132 -- 'Employers' Disclosures about Pensions and Other Postretirement Benefits' is set out below. <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Principal plans: Service cost-- benefits earned during year......... 347 375 335 Interest cost on projected benefit obligation...... 999 1,089 1,136 Expected return on plan assets..................... (1,273) (1,339) (1,364) Amortization of transition asset................... (83) (84) (82) Recognized net actuarial gain...................... (108) (87) (65) Recognized prior service cost...................... 17 14 30 Curtailment and settlement......................... (150) 12 9 Special termination benefits....................... 3 -- -- ------ ------ ------ (248) (20) (1) Other defined benefit plans.......................... 30 51 39 Defined contribution schemes......................... 121 108 103 ------ ------ ------ Total pension (income) expense....................... (97) 139 141 ====== ====== ====== </TABLE> F - 57
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 38 -- PENSIONS (CONTINUED) <TABLE> <CAPTION> UK and Other European plans US plans ---------------- ---------------- 1999 1998 1999 1998 ------ ------ ------ ------ ($ million) <S> <C> <C> <C> <C> Benefit obligation at January 1.................. 12,670 11,567 4,424 4,388 Service cost..................................... 229 221 118 154 Interest cost.................................... 723 787 276 302 Plan amendments.................................. 47 -- 71 -- Curtailments, settlements and special termination benefits -- -- (15) 12 Actuarial (gain) loss............................ 130 518 (93) 60 Plan participants' contributions................. 21 20 -- -- Settlement payments.............................. -- -- (668) (26) Benefit payments................................. (639) (619) (286) (466) Exchange adjustment.............................. (591) 176 -- -- ------ ------ ------ ------ Benefit obligation at December 31................ 12,590 12,670 3,827 4,424 ------ ------ ------ ------ Fair value of plan assets at January 1........... 17,991 15,915 5,230 4,774 Actual return on plan assets..................... 3,280 2,456 981 833 Plan participants' contributions................. 21 20 -- -- Employer contributions........................... -- 8 74 115 Settlement payments.............................. -- -- (668) (26) Benefit payments................................. (534) (515) (286) (466) Exchange adjustment.............................. (569) 107 -- -- ------ ------ ------ ------ Fair value of plan assets at December 31......... 20,189 17,991 5,331 5,230 ------ ------ ------ ------ Funded status.................................... 7,599 5,321 1,504 806 Unrecognized transition asset.................... (252) (318) (14) (32) Unrecognized net actuarial (gain) loss........... (7,012) (4,914) (740) (207) Unrecognized prior service cost.................. 135 111 13 (53) ------ ------ ------ ------ Net amount recognized............................ 470 200 763 514 ====== ====== ====== ====== Prepaid benefit cost............................. 1,704 1,545 837 656 Accrued benefit liability........................ (1,473) (1,644) (142) (190) Intangible asset................................. 78 126 5 -- Accumulated other comprehensive income........... 161 173 63 48 ------ ------ ------ ------ 470 200 763 514 ====== ====== ====== ====== </TABLE> F - 58
BP AMOCO p.l.c. AND SUBSIDIARIES 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, ---------------------------------- 1999 1998 1997 ---------- ---------- ---------- <S> <C> <C> <C> UK and other European plans: Compensation increase........................... 4.8% 4.3% 5.1% Discount rate................................... 6.5% 6.1% 7% US plans: Compensation increase........................... 4.0% 4.7% 4.7% Discount rate................................... 7.5% 6.5% 6.9% </TABLE> Plan assets are held in equity securities, fixed income securities and real estate. NOTE 39 -- OTHER POSTRETIREMENT BENEFITS Certain Group companies, principally in the United States, 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 partly funded and the accrued net liability for postretirement benefits is included within other provisions. The charge to income for postretirement benefits in 1999 of $42 million (1998 $101 million and 1997 $110 million) was assessed in accordance with independent actuarial advice using the projected unit credit method. The charge for 1999 is net of a curtailment gain of $62 million arising from the high level of severance during the year. At December 31, 1999 the independent actuaries have reassessed the obligation for postretirement benefits at $1,638 million ($1,814 million at December 31, 1998). The provision for postretirement benefits at December 31, 1999 was $2,244 million ($2,311 million at December 31, 1998). The discount rate used to assess the obligation at December 31, 1999 was 7.5% (6.5% at December 31, 1998). The assumed future healthcare cost trend rate for 2000 and subsequent years is 5%. F - 59
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 39 -- OTHER POSTRETIREMENT BENEFITS (CONCLUDED) Further information presented in compliance with the requirements of FASB Statement of Financial Accounting Standards No. 132 -- 'Employers' Disclosures about Pensions and Other Postretirement Benefits' is set out below. <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Service cost -- benefits earned during year.......... 34 39 40 Interest cost on projected benefit obligation........ 113 114 116 Expected return on plan assets....................... (4) (1) -- Recognized net actuarial gain........................ (31) (28) (24) Amortization of prior service cost recognized........ (8) (23) (22) Curtailment.......................................... (62) -- -- ------ ------ ------ Postretirement benefit expense....................... 42 101 110 ====== ====== ====== </TABLE> <TABLE> <CAPTION> 1999 1998 ------- ------- ($ million) <S> <C> <C> Benefit obligation at January 1........................... 1,814 1,709 Service cost.............................................. 34 39 Interest cost............................................. 113 114 Plan amendments........................................... 22 -- Curtailment gain.......................................... (21) -- Actuarial (gain) loss..................................... (214) 52 Benefit payments.......................................... (110) (100) ------ ------ Benefit obligation at December 31......................... 1,638 1,814 ------ ------ Fair value of plan assets at January 1.................... 49 -- Actual return on plan assets.............................. 6 9 Employer contributions.................................... (2) 40 ------ ------ Fair value of plan assets at December 31.................. 53 49 ------ ------ Funded status............................................. (1,585) (1,765) Unrecognized net actuarial gain........................... (570) (382) Unrecognized prior service cost........................... (89) (164) ------ ------ Provision for postretirement benefits..................... (2,244) (2,311) ====== ====== </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 1999........ 18 (14) Effect on postretirement obligation at December 31, 1999.... 164 (137) </TABLE> F - 60
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 40 -- CONTINGENT LIABILITIES There were contingent liabilities at December 31, 1999 in respect of guarantees and indemnities entered into as part of, and claims arising from, the ordinary course of the Group's business, upon which no material losses are likely to arise. 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 Amoco owns a 50% interest in Alyeska through a subsidiary of BP America Inc. 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 Amoco would defend the claims vigorously. 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 Amoco 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 Amoco's favor. The IRS has 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 13December1999 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. 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 Amoco does not expect these costs to have a material effect on the Group's financial position or liquidity. F - 61
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 41 -- JOINT VENTURES AND ASSOCIATED UNDERTAKINGS Summarized financial information for the Group's share of its joint ventures is shown below. The principal joint venture is the pan-European refining and marketing joint venture with ExxonMobil, which is jointly controlled. The other significant joint ventures of the BP Amoco Group at December 31, 1998 are shown in Note 46. <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Turnover.................................................... 17,614 15,428 ------ ------ Profit for the period before tax............................ 1,037 546 ------ ------ Profit for the period after tax............................. 1,032 561 ------ ------ Fixed assets................................................ 5,366 5,681 Current assets.............................................. 4,582 3,372 ------ ------ 9,948 9,053 Liabilities due within one year............................. 4,172 3,586 Liabilities due after one year.............................. 572 462 ------ ------ 5,204 5,005 ====== ====== </TABLE> Within the BP/Mobil joint venture BP Amoco operates and has a 70% interest in the fuels refining and marketing operation and has a 49% interest in the lubricants business. Funding is provided to the joint venture by both BP Amoco and ExxonMobil in proportion to their respective interests as required. Surplus cash in the joint venture is returned to BP Amoco and ExxonMobil on a regular, usually daily, basis. BP Amoco has made available to the joint venture on a long-term basis the tangible fixed assets formerly used by its European refining and marketing operations. Staff working for the fuels business are BP Amoco employees, while those working for the lubricants business are ExxonMobil employees. Staff costs for BP Amoco employees were $819 million (1998 $902 million). During the year the BP Amoco Group sold crude oil and products totalling $3,398 million (1998 $2,264 million) to the BP/Mobil joint venture and purchased crude oil and products totalling $1,791 million (1998 $1,335 million). At December 31, 1999 the outstanding balances receivable and payable were $725 million (1998 $351 million) and $278 million (1998 $144 million) respectively. In addition there were net receipts of $527 million (1998 $675 million) outstanding at December 31, 1999. The more significant associated undertakings of the BP Amoco Group at December 31, 1998 are shown in Note 46. During the year the BP Amoco Group purchased crude oil from two associated undertakings, Abu Dhabi Marine Areas and Abu Dhabi Petroleum to the value of $935 million (1998 $715 million). At December 31, 1999 $119 million (1998 $45 million) was payable in respect of these purchases. During the year the BP Amoco Group sold chemical feedstocks totalling $460 million (1998 $395 million) to Erdoelchemie, an associated undertaking, and bought petrochemicals, mainly polyethylene, to the value of $77 million (1998 $76 million). At December 31, 1998 the outstanding balance receivable from Erdolchemie was $1 million (1998 $1 million). F - 62
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 42-- OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (a) CAPITALIZED COSTS AT DECEMBER 31 <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> 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 ======== ======== ======== ======== ======== 1997 Gross capitalized costs: Proved properties.................... 21,250 2,917 34,166 14,137 72,470 Unproved properties.................. 323 55 914 1,776 3,068 -------- -------- -------- -------- -------- 21,573 2,972 35,080 15,913 75,538 Accumulated depreciation (b)........... 10,975 1,736 20,924 7,889 41,524 -------- -------- -------- -------- -------- Net capitalized costs.................. 10,598 1,236 14,156 8,024 34,014 ======== ======== ======== ======== ======== </TABLE> F - 63
BP AMOCO p.l.c. AND SUBSIDIARIES 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> 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 ======== ======== ======== ======== ======== 1997 Acquisition of properties: Proved............................... -- 95 7 7 109 Unproved............................. 15 3 121 26 165 -------- -------- -------- -------- -------- 15 98 128 33 274 Exploration and appraisal costs (c).... 192 133 524 942 1,791 Development costs...................... 1,463 161 1,744 1,714 5,082 -------- -------- -------- -------- -------- Total costs............................ 1,670 392 2,396 2,689 7,147 ======== ======== ======== ======== ======== </TABLE> F - 64
BP AMOCO p.l.c. AND SUBSIDIARIES 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> 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 ======== ======== ======== ======== ======== 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> F - 65
BP AMOCO p.l.c. AND SUBSIDIARIES 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> 1997 Turnover (d): Third parties........................ 3,175 900 3,456 1,465 8,996 Sales between businesses............. 1,322 -- 3,315 2,972 7,609 -------- -------- -------- -------- -------- 4,497 900 6,771 4,437 16,605 -------- -------- -------- -------- -------- Exploration expense.................... 156 79 273 454 962 Production costs....................... 743 176 1,378 944 3,241 Production taxes....................... 283 19 446 536 1,284 Other costs (income) (e)............... 50 (11) 720 690 1,449 Depreciation and amounts provided...... 1,236 185 1,163 707 3,291 -------- -------- -------- -------- -------- 2,468 448 3,980 3,331 10,227 -------- -------- -------- -------- -------- Profit before taxation (f)............. 2,029 452 2,791 1,106 6,378 Allocable taxes........................ 655 206 896 501 2,258 -------- -------- -------- -------- -------- Results of operations ................. 1,374 246 1,895 605 4,120 ======== ======== ======== ======== ======== </TABLE> - ---------- The Group's share of associated undertakings results of operations in 1999 was a profit of $204 million (1998 $40 million and 1997 $13 million) after adding a tax credit of $6 million (1998 $19 million and 1997 nil). The Group's share of associated undertakings net capitalized costs at December 31, 1999 was $1,442 million (December 31, 1998 $2,212 million and December 31, 1997 $2,662 million). The Group's share of associated undertakings costs incurred in 1999 was $49 million (1998 $282 million and 1997 $1,349 million). (a) Information given in this note relates to the Group's oil and natural gas activities. Midstream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main midstream activities are the Alaskan transportation facilities, the Forties Pipeline system, the Central Area Transmission system and Ruhrgas gas distribution operations. Profits (losses) on sale of businesses and fixed assets and restructuring costs relating to the oil and natural gas exploration and production activities which have been accounted as exceptional items, are also excluded. (b) Accumulated depreciation consists of depreciation, depletion and amortization related to oil and natural gas producing activities. (c) Exploration and appraisal drilling expenditure and licence acquisition costs are initially capitalized within intangible fixed assets in accordance with the Group's accounting policy. (d) Turnover represents sales of production excluding royalty oil where royalty is payable in kind. (e) Includes cost of royalty oil not taken in kind and property taxes. F - 66
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 42-- OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (a) (CONCLUDED) (f) The exploration and production total replacement cost operating profit comprises: <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- ($ million) <S> <C> <C> <C> <C> <C> 1999 Exploration and production activities --Group (as above)..................... 2,094 478 1,835 1,804 6,211 --Associated undertakings.............. -- -- 45 153 198 Midstream activities................... 230 180 263 112 785 -------- -------- -------- -------- -------- Total replacement cost operating profit 2,324 658 2,143 2,069 7,194 ======== ======== ======== ======== ======== 1998 Exploration and production activities --Group (as above)..................... 1,384 201 840 (84) 2,341 --Associated undertakings.............. (15) -- 31 5 21 Midstream activities................... 297 171 307 94 869 -------- -------- -------- -------- -------- Total replacement cost operating profit 1,666 372 1,178 15 3,231 ======== ======== ======== ======== ======== 1997 Exploration and production activities --Group (as above)..................... 2,029 452 2,791 1,106 6,378 --Associated undertakings.............. (8) -- 19 2 13 Midstream activities................... 290 159 319 226 994 -------- -------- -------- -------- -------- Total replacement cost operating profit 2,311 611 3,129 1,334 7,385 ======== ======== ======== ======== ======== </TABLE> NOTE 43 -- NEW ACCOUNTING STANDARD The BP Amoco Group adopted Financial Reporting Standard No.12 `Provisions, Contingent Liabilities and Contingent Assets' (FRS12) with effect from January 1, 1999. This standard changes the criteria for recognizing provisions for such costs as decommissioning, environmental liabilities, onerous contracts and restructuring charges. It also requires provisions for liabilities which may not be settled for a number of years to be discounted to their net present value. The adoption of this standard has been treated as a change in accounting policy. Comparative figures have been restated to reflect this change in accounting policy. The principal effects of the adoption of FRS12 are as follows: (a) Provisions for environmental liabilities are determined on a discounted basis as the effect of the time value of money is material. Previously these liabilities were on an undiscounted basis. (b) Provisions for decommissioning are recognized in full, on a discounted basis, at the commencement of oil and natural gas production. The BP Amoco Group's prior practice was to accrue the expected cost of decommissioning oil and natural gas production facilities on a unit-of-production basis over the life of the field. FRS12 also requires the BP Amoco Group to capitalize an amount equivalent to the provision as a tangible fixed asset and to amortize this amount over the life of the field on a unit-of-production basis. (c) The unwinding of the discount, which represents a period-by-period cost, is included within interest expense. F - 67
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 43 -- NEW ACCOUNTING STANDARD (CONCLUDED) (d) Liabilities in respect of certain onerous contracts have been recognized. The effect of the change in accounting policy has been for 1999 to increase total replacement cost operating profit and profit for the year, and for 1998 to increase total replacement cost operating profit and reduce the profit for the year as set out below. <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Total replacement cost operating profit....................... 121 84 100 Restructuring costs........................................... 66 -- -- Refinery network rationalization.............................. -- -- (118) European refining and marketing joint venture implementation.. -- -- (265) Interest expense.............................................. (110) (124) (127) Taxation...................................................... -- -- 53 ------ ------ ------ Profit (loss) for the period.................................. 77 (40) (357) ====== ====== ====== The adjustments to tangible assets and provisions for liabilities and charges at December 31, 1998 are as follows: Tangible assets......................................................... 415 Other creditors......................................................... 62 Other provisions........................................................ 238 ------ BP Amoco shareholders' interest.......................................... 715 ====== </TABLE> NOTE 44 -- US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The consolidated financial statements of the BP Amoco 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 Amoco 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. 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. F - 68
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 44-- US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED) (A) GROUP CONSOLIDATION (CONCLUDED) The following summarizes the reclassifications for associates and joint ventures necessary to accord with US GAAP. <TABLE> <CAPTION> Year ended December 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 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> <TABLE> <CAPTION> Year ended December 1997 -------------------------------------------- As US GAAP Reported Reclassification Presentation ------------- ---------------- ------------ ($ million) <S> <C> <C> <C> CONSOLIDATED STATEMENT OF INCOME Other income................................. 662 586 1,248 Share of profits of JVs and associated undertakings 1,100 (1,100) -- Exceptional items before taxation............ 128 123 251 Inventory holding gains (losses)............. (939) 200 (739) Interest expense............................. 1,035 (83) 952 Taxation..................................... 3,013 (108) 2,905 Profit for the year.......................... 5,673 -- 5,673 </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 - 69
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 44-- 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 US 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 - 70
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 44-- US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED) (F) DEFERRED TAXATION (CONCLUDED) At December 31, 1999, the adjustment to the carrying amount of fixed assets was $1,210 million ($1,325 million at December 31, 1998) and the related deferred tax liability $1,145 million ($1,236 million at December 31, 1998). The charge for depreciation in 1999 in respect of these assets was $115 million (1998 $123 million and 1997 $162 million) and the credit for taxation $91 million (1998 $256 million and 1997 $166 million). The UK/US GAAP adjustment for deferred taxation may be summarized as follows: <TABLE> <CAPTION> 1999 1998 ------ ------ ($ million) <S> <C> <C> Increase in provision from restricted liability to gross potential liability............................................. 5,356 4,677 Tax liability resulting from business combination................. 1,145 1,236 Net tax asset on sale and leaseback of Chicago office building, severance costs, European joint venture implementation costs, and other adjustments........................................... (419) (137) ------ ------ 6,082 5,776 ====== ====== </TABLE> The major components of deferred tax liabilities and assets on a US GAAP basis were as follows: <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Depreciation.......................................... (11,394) (11,087) Other taxable temporary differences................... (1,733) (1,249) ------ ------ Total deferred tax liabilities........................ (13,127) (12,336) ------ ------ Petroleum revenue tax................................. 332 420 Decommissioning and other provisions.................. 2,362 2,279 Advance corporation tax............................... -- 33 Tax credit and loss carry forward..................... 1,726 1,870 Other deductible temporary differences................ 1,141 1,080 ------ ------ Gross deferred tax assets............................. 5,561 5,682 Valuation allowance................................... (299) (754) ------ ------ Net deferred tax assets............................... 5,262 4,928 ------ ------ Net deferred tax liability*........................... 7,865 7,408 ====== ====== </TABLE> - ---------- * Primarily noncurrent. F - 71
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 44-- 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 amortised 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. F - 72
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 44-- US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (CONTINUED) The following is a summary of the adjustments to profit for the year and to BP Amoco 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, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million except per share amounts) <S> <C> <C> <C> Profit as reported in the consolidated statement of income.. 5,008 3,220 5,673 Adjustments: Depreciation charge....................................... (81) (76) (101) Decommissioning and environmental expense................. (165) (131) (161) Onerous property leases................................... 133 -- -- Interest expense.......................................... 110 124 127 Sale and leaseback of fixed assets........................ (37) (211) -- Deferred taxation......................................... (378) (72) 41 Other..................................................... 6 (28) 107 ------ ------ ------ Profit for the year as adjusted to accord with US GAAP...... 4,596 2,826 5,686 Dividend requirements on preference shares.................. 2 1 1 ------ ------ ------ Profit for the year applicable to Ordinary Shares as adjusted to accord with US GAAP........................ 4,594 2,825 5,685 ====== ====== ====== Profit for the year as adjusted: Per Ordinary Share - cents Basic..................................................... 23.70 14.72 29.62 Diluted................................................... 23.56 14.66 29.46 ====== ====== ====== Per American Depositary Share - cents Basic..................................................... 142.20 88.32 177.72 Diluted................................................... 141.36 87.96 176.76 ====== ====== ====== </TABLE> BP AMOCO SHAREHOLDERS' INTEREST <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> BP Amoco shareholders' interest as reported in the consolidated balance sheet..................................... 43,281 42,501 Adjustments: Fixed assets.................................................... 1,237 1,112 Ordinary shares held for future awards to employees............. (456) (489) Sale and leaseback of Chicago office building................... (413) (413) Decommissioning and environmental provisions.................... (499) (238) Onerous property leases......................................... 139 -- Deferred taxation............................................... (6,082) (5,776) Fourth quarterly dividend....................................... 972 968 Pension liability adjustment.................................... (144) (143) Other........................................................... (197) (188) ------ ------ BP Amoco shareholders' interest as adjusted to accord with US GAAP 37,838 37,334 ====== ====== </TABLE> F - 73
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 44-- 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, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> Profit for the period as adjusted to accord with US GAAP.... 4,596 2,826 5,686 Currency translation differences............................ (921) 55 (1,587) Pension liability adjustment................................ (1) (33) 7 ------ ------ ------ Comprehensive income........................................ 3,674 2,848 4,106 ====== ====== ====== </TABLE> Accumulated other comprehensive income at December 31, 1999 comprised currency translation losses of $1,374 million (December 31, 1998 losses $453 million) and pension liability adjustments of $144 million (December 31, 1998 $143 million). CONSOLIDATED BALANCE SHEET Under US GAAP Trade and Other receivables due after one year of $3,455 million at December 31, 1999 ($3,305 million at December 31, 1998), included within current assets, would have been classified as noncurrent assets. Borrowing under US Industrial Revenue/Municipal Bonds of $1,376 million (December 31,1998 $1,277 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) management of liquid resources; and (x) financing. 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 - 74
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 44-- 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, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> OPERATING ACTIVITIES Profit after taxation................................ 5,146 3,283 5,824 Adjustments to reconcile profit after tax to net cash provided by operating activities: Depreciation and amounts provided.................. 4,965 5,301 5,117 Exploration expenditure written off................ 304 373 365 Share of profit (losses) of joint ventures and associated undertakings less dividends received............. (536) (136) (36) Profit (loss) on sale of businesses and fixed assets 379 (963) (563) Working capital decrease (increase) (a)............ (1,676) 380 2,370 Other.............................................. 318 255 382 ------ ------ ------ NET CASH PROVIDED BY OPERATING ACTIVITIES............ 8,900 8,493 13,459 ------ ------ ------ INVESTING ACTIVITIES Capital expenditures................................. (6,314) (9,026) (8,995) Acquisitions......................................... (102) (314) -- Investment in associated undertakings................ (197) (396) (1,021) Net investment in joint ventures..................... (750) 708 (1,967) Proceeds from disposal of assets..................... 2,441 2,167 1,832 ------ ------ ------ NET CASH USED IN INVESTING ACTIVITIES................ (4,922) (6,861) (10,151) ------ ------ ------ FINANCING ACTIVITIES Proceeds from shares issued (repurchased) ........... 245 (423) (1,250) Proceeds from long-term financing.................... 2,140 2,078 1,124 Repayments of long-term financing.................... (2,268) (1,208) (863) Net increase (decrease) in short-term debt........... 837 (70) (23) Dividends paid -- Shareholders....................... (4,135) (2,408) (2,437) -- Minority shareholders.............. (151) (130) -- ------ ------ ------ NET CASH USED IN FINANCING ACTIVITIES................ (3,332) (2,161) (3,449) ------ ------ ------ Currency translation differences relating to cash and cash equivalents............................... 15 (15) (28) ------ ------ ------ INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS..... 661 (544) (169) Cash and cash equivalents at beginning of year....... 794 1,338 1,507 ------ ------ ------ Cash and cash equivalents at end of year............. 1,455 794 1,338 ====== ====== ====== </TABLE> - ---------- <TABLE> <CAPTION> <S> <C> <C> <C> (a)Working capital: Inventories (increase) decrease ................... (1,562) 584 1,740 Receivables (increase) decrease ................... (3,854) 1,777 2,119 Current liabilities (excluding finance debt) increase (decrease)............................... 3,740 (1,981) (1,489) ------ ------ ------ (1,676) 380 2,370 ====== ====== ====== </TABLE> F - 75
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 44-- 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 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. The Company has not yet completed its evaluation of the impact of adopting SFAS 133 on the Group's results of operations and financial position as adjusted to accord with US GAAP. START-UP COSTS: Effective January 1, 1999 the Group adopted the American Institute of Certified Public Accountants' issued Statement of Position No. 98-5, `Reporting on the Costs of Start-up Activities' (SOP 98-5). This Statement requires costs associated with start-up activities and organization costs be expensed as incurred. Under its previous practice, the Group generally expensed such costs as incurred. The adoption of SOP 98-5 had no impact on the Group's results of operations and financial positions as adjusted to accord with US GAAP. NOTE 45 -- BUSINESS AND GEOGRAPHICAL ANALYSIS BP Amoco has three reportable operating segments -- Exploration and Production, 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, natural gas processing and natural gas marketing (midstream activities). 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 - 76
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 45-- BUSINESS AND GEOGRAPHICAL ANALYSIS (CONTINUED) BY BUSINESS <TABLE> <CAPTION> Other Exploration Refining businesses and and and Production Marketing Chemicals corporate(a) Eliminations Total ---------- --------- --------- ---------- ------------ ----- ($ million) 1999 <S> <C> <C> <C> <C> <C> <C> Group turnover--third parties... 13,949 60,369 9,050 198 -- 83,566 --sales between businesses(b)... 7,700 2,524 342 -- (10,566) -- ------- ------- ------- ------- ------- ------- 21,649 62,893 9,392 198 (10,566 83,566 ------- ------- ------- ------- ------- ------- Share of joint venture sales 17,614 ------- 101,180 ------- Equity accounted income (c).... 476 503 125 54 1,158 ------- ------- ------- ------- ------- Total replacement cost operating profit (loss) (d)............ 7,194 1,840 686 (826) 8,894 Exceptional items (e).......... (1,097) (334) (257) (592) (2,280) Inventory holding gains (losses) (1) 1,613 116 -- 1,728 ------- ------- ------- ------- ------- Historical cost profit (loss) before interest and tax...... 6,096 3,119 545 (1,418) 8,342 ------- ------- ------- ------- ------- Total assets (f)............... 46,649 27,248 13,021 2,643 89,561 Operating capital employed (g). 37,322 14,358 10,048 1,192 62,920 Depreciation and amounts provided (h)................. 3,705 810 632 206 5,353 Capital expenditure and acquisitions (i) 4,212 1,634 1,215 284 7,345 1998 Group turnover--third parties.. 12,216 46,625 9,312 151 -- 68,304 --sales between businesses (b). 5,060 1,812 379 48 (7,299) -- ------- ------- ------- ------- ------- ------- 17,276 48,437 9,691 199 (7,299) 68,304 ------- ------- ------- ------- ------- ------- Share of joint venture sales 15,428 ------- 83,732 ------- Equity accounted income (c).... 244 852 150 101 1,347 ------- ------- ------- ------- ------- Total replacement cost operating profit (loss) (d)............ 3,231 2,564 1,100 (374) 6,521 Exceptional items (e).......... 396 394 43 17 850 Inventory holding gains (losses) (17) (1,228) (146) -- (1,391) ------- ------- ------- ------- ------- Historical cost profit (loss) before interest and tax...... 3,610 1,730 997 (357) 5,980 ------- ------- ------- ------- ------- Total assets (f)............... 47,808 21,029 12,562 3,516 84,915 Operating capital employed (g). 38,819 12,563 10,178 (579) 60,981 Depreciation and amounts provided (h)................. 4,272 790 497 115 5,674 Capital expenditure and acquisitions (i)............. 6,318 1,937 1,606 501 10,362 </TABLE> F - 77
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 45-- BUSINESS AND GEOGRAPHICAL ANALYSIS (CONTINUED) <TABLE> <CAPTION> Other Exploration Refining businesses and and and Production Marketing Chemicals corporate(a) Eliminations Total ---------- --------- --------- ---------- ------------ ----- ($ million) <S> <C> <C> <C> <C> <C> <C> 1997 Group turnover--third parties.. 15,475 65,283 10,853 149 -- 91,760 --sales between businesses (b). 7,696 2,421 592 -- (10,709) -- ------- ------- ------- ------- ------- ------- 23,171 67,704 11,445 149 (10,709) 91,760 ------- ------- ------- ------- ------- ------- Share of joint venture sales 16,804 ------- 108,564 ------- Equity accounted income (c)... 292 604 125 79 1,100 ------- ------- ------- ------- ------- Total replacement cost operating profit (loss) (d)........... 7,385 2,292 1,530 (524) 10,683 Exceptional items (e)......... 587 (422) (15) (22) 128 Inventory holding gains (losses) 12 (849) (102) -- (939) ------- ------- ------- ------- ------- Historical cost profit (loss) before interest and tax..... 7,984 1,021 1,413 (546) 9,872 ------- ------- ------- ------- ------- Total assets (f).............. 46,024 24,055 12,141 4,059 86,279 Operating capital employed (g) 36,428 14,073 9,672 232 60,405 Depreciation (h).............. 3,957 842 559 124 5,482 Capital expenditure and acquisitions 7,879 1,824 1,145 572 11,420 </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> 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) 14,748 4,434 27,426 16,312 62,920 Capital expenditure and acquisitions (i)........... 1,518 831 2,963 2,033 7,345 </TABLE> F - 78
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 45-- 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> 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> <TABLE> <CAPTION> <S> <C> <C> <C> <C> <C> <C> 1997 Group turnover - -- third parties(k)........... 27,473 7,943 40,322 16,022 91,760 - -- sales between areas........ 3,787 553 1,438 3,377 (9,155) -- ------ ------ ------ ------ ------- ------ 31,260 8,496 41,760 19,399 (9,155) 91,760 ------ ------ ------ ------ ------- Share of joint venture sales.. 4,584 15,414 41 71 (3,306) 16,804 ------- 108,564 ------- Equity accounted income (c).. 26 758 84 232 1,100 ------ ------ ------ ------ ------- Total replacement cost operating profit (d)....... 2,767 1,332 4,360 2,224 10,683 Exceptional items (e)........ (133) (205) 456 10 128 Inventory holding gains (losses) (85) (103) (647) (104) (939) ------ ------ ------ ------ ------- Historical cost profit before interest and tax........... 2,549 1,024 4,169 2,130 9,872 ------ ------ ------ ------ ------- Total assets (f)............. 22,520 9,246 36,533 17,980 86,279 Operating capital employed (g) 12,853 4,821 26,456 16,275 60,405 Capital expenditure and acquisitions (i)........... 2,413 1,243 3,315 4,449 11,420 </TABLE> - ---------- (a) Other businesses and corporate comprises Finance, BP Solarex, the Group's coal interest, 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 - 79
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 45-- BUSINESS AND GEOGRAPHICAL ANALYSIS (CONCLUDED) (e) Exceptional items comprise profit (loss) on sale of businesses and sale of fixed assets of $(337) million in 1999 (1998 $1,048 million profit and 1997 $440 million profit), restructuring costs in 1999 of $1,943, merger expenses in 1998 of $198 million refinery network rationalization costs in 1997 of $47 million and European refining and marketing joint venture implementation costs in 1997 of $265 million. (f) Total assets comprise fixed and current assets and include investments in joint ventures and associated undertakings analyzed between activities as follows: <TABLE> <CAPTION> Other Exploration Refining businesses and and and Production Marketing Chemicals corporate(a) Total ---------- ---------- ---------- ---------- ---------- ($ million) <S> <C> <C> <C> <C> <C> 1999.................... 3,312 4,771 1,350 105 9,538 ---------- ---------- ---------- ---------- ---------- 1998.................... 3,416 4,345 1,281 125 9,167 ---------- ---------- ---------- ---------- ---------- 1997.................... 3,782 4,796 1,270 130 9,978 ---------- ---------- ---------- ---------- ---------- </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 $624 million in 1999 (1998 $620 million and 1997 $646 million) for the BP/Mobil joint venture. (j) United Kingdom area includes the UK-based international activities of Refining and Marketing. (k) Turnover to third parties is stated by origin which is not materially different from turnover by destination. NOTE 46-- SUMMARIZED FINANCIAL INFORMATION ON ASSOCIATED UNDERTAKINGS AND JOINT VENTURES A summarized statement of income and assets and liabilities based on latest information available, with respect to the Group's equity accounted associated undertakings and joint ventures, is set out below: <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997(a) ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and other operating revenue.................... 41,180 42,801 45,330 Gross profit......................................... 7,715 7,484 7,641 Profit for the year.................................. 2,641 675 1,754 ====== ====== ====== </TABLE> <TABLE> <CAPTION> December 31, ------------ 1999 1998 ------ ------ ($ million) <S> <C> <C> Fixed and other assets............................... 17,398 25,534 Current assets....................................... 12,232 11,626 ------ ------ 29,630 37,160 Current liabilities.................................. (10,929) (12,703) Noncurrent liabilities............................... (5,876) (7,604) ------ ------ Net assets........................................... 12,825 16,853 ====== ====== </TABLE> - ---------- F - 80
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 46-- SUMMARIZED FINANCIAL INFORMATION ON ASSOCIATED UNDERTAKINGS AND JOINT VENTURES (CONCLUDED) (a) Excludes Sidanco and Rusia. The more important associated undertakings and joint ventures of the Group at December 31, 1999 and the percentage of equity capital owned or joint venture interest are: <TABLE> <CAPTION> % Country of Principal operation activities ASSOCIATED UNDERTAKINGS <S> <C> <C> <C> Abu Dhabi Marine Areas..... 33 Abu Dhabi Crude oil production Abu Dhabi Petroleum........ 24 Abu Dhabi Crude oil production Erdolchemie................ 50 Germany Chemicals Ruhrgas.................... 25 Germany Gas distribution Sidanco (b)................ 10 Russia Integrated oil operations Rusia...................... 25 Russia Exploration and production China American Petroleum Co. 50 Taiwan Chemicals JOINT VENTURES BP/Mobil................... 70/49(c) Europe Refining and marketing Empresa Petrolera Chaco.... 30 Bolivia Exploration and production Pan American Energy........ 60 Argentina Exploration and production CaTo Finance Partnership... 50 UK Finance </TABLE> - ---------- (b) 20% voting interest. (c) Fuels/lubricants NOTE 47 -- SUMMARIZED FINANCIAL INFORMATION ON CERTAIN US SUBSIDIARIES BP AMERICA INC. (a)(b) <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and other operating revenue.................... 15,727 12,502 16,789 Gross profit (c)..................................... 2,539 1,819 3,204 Profit for the year ................................. 797 525 928 ====== ====== ====== </TABLE> <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Fixed and other assets............................... 13,790 13,789 Current assets....................................... 5,278 3,002 ------ ------ Total assets......................................... 19,068 16,791 ====== ====== Current liabilities.................................. 6,283 5,172 Noncurrent liabilities............................... 6,199 5,822 Shareholders' interest............................... 6,586 5,797 ------ ------ Total liabilities and shareholders' interest......... 19,068 16,791 ====== ====== </TABLE> F - 81
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONTINUED) NOTE 47-- SUMMARIZED FINANCIAL INFORMATION ON CERTAIN USSUBSIDIARIES (CONTINUED) THE STANDARD OIL COMPANY (a)(b) <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and other operating revenue.................... 15,301 12,111 16,312 Gross profit (c)..................................... 2,337 1,617 2,897 Profit for the year.................................. 1,057 655 1,008 ====== ====== ====== </TABLE> <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Fixed and other assets............................... 12,584 12,387 Current assets....................................... 6,664 4,547 ------ ------ Total assets......................................... 19,248 16,934 ====== ====== Current liabilities.................................. 4,303 2,772 Noncurrent liabilities............................... 5,363 5,630 Shareholders' interest............................... 9,582 8,532 ------ ------ Total liabilities and shareholders' interest......... 19,248 16,934 ====== ====== </TABLE> BP PIPELINES (ALASKA) INC. (a)(b) <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and other operating revenue.................... 476 547 638 Gross profit (c)..................................... 193 239 242 Profit for the year.................................. 113 140 123 ====== ====== ====== </TABLE> <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Fixed and other assets............................... 1,290 1,362 Current assets....................................... 853 803 ------ ------ Total assets......................................... 2,143 2,165 ====== ====== Current liabilities.................................. 128 152 Noncurrent liabilities............................... 967 994 Shareholders' interest............................... 1,048 1,019 ------ ------ Total liabilities and shareholders' interest......... 2,143 2,165 ====== ====== </TABLE> F - 82
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONCLUDED) NOTE 47-- SUMMARIZED FINANCIAL INFORMATION ON CERTAIN USSUBSIDIARIES (CONTINUED) BP EXPLORATION (ALASKA) INC. (a)(b) <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and other operating revenue.................... 8,645 5,666 9,228 Gross profit (loss)(c)............................... 365 (65) 1,150 Profit (loss)for the year............................ 242 (60) 959 ====== ====== ====== </TABLE> <TABLE> <CAPTION> December 31, --------------- 1999 1998 ------ ------ ($ million) <S> <C> <C> Fixed and other assets............................... 10,124 9,704 Current assets....................................... 3,117 1,836 ------ ------ Total assets......................................... 13,241 11,540 ====== ====== Current liabilities.................................. 2,119 628 Noncurrent liabilities............................... 1,536 1,582 Shareholders' interest............................... 9,586 9,330 ------ ------ Total liabilities and shareholders' interest......... 13,241 11,540 ====== ====== </TABLE> - ---------- (a) BP America Inc. is a wholly-owned subsidiary of BP Amoco p.l.c.; The Standard Oil Company is a wholly-owned subsidiary of BP America Inc.; and BP Pipelines (Alaska) Inc. and BP Exploration (Alaska) Inc. are wholly-owned subsidiaries of The Standard Oil Company. (b) As a result of adopting FRS 12 (see Note 43), profit for the year ended December 31, 1999 for BP America Inc., The Standard Oil Company, BP Pipelines (Alaska) Inc. and BP Exploration (Alaska) Inc. was increased by $22 million, $22 million $8 million and $11 million respectively. In addition, the adoption of FRS 12 resulted in the restatement of certain prior year financial information as follows - (i) shareholders' interest at December 31, 1998 for BP America Inc., The Standard Oil Company, BP Pipelines (Alaska) Inc. and BP Exploration (Alaska) Inc. was increased by $770 million, $754 million, $281 million and $362 million, respectively; (ii) profit for the year ended December 31, 1998 for BP America Inc. The Standard Oil Company and BP Pipelines (Alaska) Inc. was decreased by $37 million, $35 million, and $9 million respectively and loss for the year ended December 31, 1998 for BP Exploration (Alaska) Inc. was increased by $7 million; (iii) profit for the year ended December 31, 1997 for BP America Inc., The Standard Oil Company, BP Pipelines (Alaska) Inc. was decreased by $35 million, $35 million, $7 million and $4 million respectively. (c) Gross profit (loss) equals sales and other operating revenue less associated costs, which exclude distribution and administration expenses and exploration expense. (d) During 1997, as part of a restructuring of ownership interests among certain wholly owned subsidiaries of BP America Inc., the obligation for certain employee benefits provided in the financial statements of BP Exploration (Alaska) Inc. was transferred to The Standard Oil Company. As a result of this transfer, profit for 1997 for BP Exploration (Alaska) Inc. includes a credit of $223 million. F - 83
BP AMOCO p.l.c. AND SUBSIDIARIES NOTES TO FINANCIAL STATEMENTS (CONCLUDED) NOTE 47-- SUMMARIZED FINANCIAL INFORMATION ON CERTAIN USSUBSIDIARIES (CONCLUDED) (e) In August 1998, The Standard Oil Company completed the sale of its Lima, Ohio, refinery and related terminal facilities. The after-tax gain resulting from this sale amounts to $255 million, which includes the write-back of certain provisions no longer required. (f) During 1998, certain tax liabilities provided in the financial statements of BP America Inc. were transferred to The Standard Oil Company, BP Pipelines (Alaska) Inc. and BP Exploration (Alaska) Inc. As a result of this transfer profit (loss) for 1998 for The Standard Oil Company, BP Pipelines (Alaska) Inc. and BP Exploration (Alaska) Inc. includes a tax charge of $80 million, $22 million and $28 million, respectively. (g) Profit for the year ended December 31, 1999 for BP America Inc., The Standard Oil Company and BP Exploration (Alaska) Inc. includes a pretax charge of $100 million relating to the write-down of the investment in the Badami oilfield. (h) Profit for the year ended December 31, 1999 for BP America Inc., The Standard Oil Company and BP Exploration (Alaska) Inc. includes pre-tax restructuring charges of $222 million, $153 million and $49 million respectively F - 84
BP AMOCO p.l.c. AND SUBSIDIARIES 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, 1999, 1998 and 1997. ESTIMATED NET PROVED RESERVES OF CRUDE OIL (a) <TABLE> <CAPTION> United Rest of Rest of Kingdom Europe USA World Total -------- -------- -------- -------- -------- (millions of barrels) 1999 <S> <C> <C> <C> <C> <C> 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 ======== ======== ======== ======== ======== </TABLE> <TABLE> <CAPTION> ASSOCIATED UNDERTAKINGS BP Amoco share <S> <C> 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 AMOCO SHARE OF ASSOCIATED UNDERTAKINGS...................... 7,572 ====== </TABLE> F - 85
BP AMOCO p.l.c. AND SUBSIDIARIES 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) 1998 <S> <C> <C> <C> <C> <C> 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 ======== ======== ======== ======== ======== </TABLE> <TABLE> <CAPTION> ASSOCIATED UNDERTAKINGS BP Amoco share <S> <C> At January 1..................................................................... 1,110 Purchases of reserves-in-place................................................. 90 Production..................................................................... (72) ------ At December 31................................................................... 1,128 ====== TOTAL GROUP AND BP AMOCO SHARE OF ASSOCIATED UNDERTAKINGS....................... 8,432 ====== </TABLE> F - 86
BP AMOCO p.l.c. AND SUBSIDIARIES 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) 1997 <S> <C> <C> <C> <C> <C> SUBSIDIARY UNDERTAKINGS At January 1 Developed............................ 655 198 2,933 911 4,697 Undeveloped.......................... 924 49 924 731 2,628 -------- -------- -------- -------- -------- 1,579 247 3,857 1,642 7,325 ======== ======== ======== ======== ======== Changes in year attributable to: Revisions of previous estimates...... 33 13 139 50 235 Purchases of reserves-in-place....... 9 67 364 48 488 Extensions, discoveries and other additions.................... 88 28 338 144 598 Improved recovery.................... 35 1 66 34 136 Production........................... (160) (42) (302) (140) (644) Sales of reserves-in-place........... (61) (27) (213) (225) (526) -------- -------- -------- -------- -------- (56) 40 392 (89) 287 ======== ======== ======== ======== ======== At December 31 Developed............................ 779 241 3,039 916 4,975 Undeveloped.......................... 744 46 1,210 637 2,637 -------- -------- -------- -------- -------- 1,523 287 4,249(b)(c) 1,553 7,612 ======== ======== ======== ======== ======== </TABLE> <TABLE> <CAPTION> ASSOCIATED UNDERTAKINGS BP Amoco share <S> <C> At January 1..................................................................... 984 Net revisions and other changes................................................ (23) Purchases of reserves-in-place................................................. 194 Production..................................................................... (45) ------ At December 31................................................................... 1,110(e) ====== TOTAL GROUP AND BP AMOCO SHARE OF ASSOCIATED UNDERTAKINGS....................... 8,722 ====== </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 94 million barrels (nil barrels at December 31, 1998 and 65 million barrels at December 31, 1997) 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) Minority interest in Altura Energy included 309 million barrels of crude oil (280 million barrels at December 31, 1998 and 334 million barrels at December 31,1997). ASSOCIATED UNDERTAKINGS (d) Transfer from associated to subsidiary undertakings comprise reserves in Crescendo Resources after the acquisition of the majority interest from Repsol YPF. (e) Excludes reserves in Sidanco and Rusia. F - 87
BP AMOCO p.l.c. AND SUBSIDIARIES 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> 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 ======== ======== ======== ======== ======== </TABLE> <TABLE> <CAPTION> ASSOCIATED UNDERTAKINGS BP Amoco share <S> <C> 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 AMOCO SHARE OF ASSOCIATED UNDERTAKINGS.................... 35,526 ====== </TABLE> F - 88
BP AMOCO p.l.c. AND SUBSIDIARIES 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) 1998 <S> <C> <C> <C> <C> <C> 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 ======== ======== ======== ======== ======== </TABLE> <TABLE> <CAPTION> ASSOCIATED UNDERTAKINGS BP Amoco share <S> <C> 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 AMOCO SHARE OF ASSOCIATED UNDERTAKINGS.................... 32,767 ====== </TABLE> F - 89
BP AMOCO p.l.c. AND SUBSIDIARIES 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) 1997 <S> <C> <C> <C> <C> <C> At January 1 Developed............................ 3,085 402 11,722 5,508 20,717 Undeveloped.......................... 2,204 76 1,617 5,735 9,632 -------- -------- -------- -------- -------- 5,289 478 13,339 11,243 30,349 ======== ======== ======== ======== ======== Changes in year attributable to: Revisions of previous estimates...... 94 -- (227) 992 859 Purchases of reserves-in-place....... 196 13 283 1,007 1,499 Extensions, discoveries and other additions.................... 122 289 1,035 1,221 2,667 Improved recovery.................... 10 1 99 200 310 Production........................... (519) (70) (950)(b) (629) (2,168) Sales of reserves-in-place........... (163) (289) (1,476) (1,214) (3,142) -------- -------- -------- -------- -------- (260) (56) (1,236) 1,577 25 ======== ======== ======== ======== ======== At December 31 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 (c) 12,820 30,374 ======== ======== ======== ======== ======== </TABLE> <TABLE> <CAPTION> ASSOCIATED UNDERTAKINGS BP Amoco share <S> <C> At January 1.................................................................. -- Net revisions and other changes............................................. 54 Purchases of reserves-in-place.............................................. 1,723 Production.................................................................. (29) ------ At December 31................................................................ 1,748 ====== TOTAL GROUP AND BP AMOCO SHARE OF ASSOCIATED UNDERTAKINGS.................... 32,122 ====== </TABLE> - ---------- (a) Net proved reserves of natural gas exclude production royalties due to others. (b) Includes 77 billion cubic feet of natural gas consumed in Alaskan operations (1998, 79 billion cubic feet and 1997, 81 billion cubic feet). (c) Minority interest in Altura Energy included 155 billion cubic feet of natural gas (117 billion cubic feet at December 31, 1998 and 161 billion cubic feet at December 31, 1997). ASSOCIATED UNDERTAKINGS (d) Transfers from associated to subsidiary undertakings comprise reserves in Crescendo Resources after the acquisition of the majority interest from Repsol YPF. (e) Excludes reserves in Sidanco and Rusia. F - 90
BP AMOCO p.l.c. AND SUBSIDIARIES 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 Amoco 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, 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 ======== ======== ======== ======== ======== AT DECEMBER 31, 1997 Future cash inflows (a)................ 38,400 6,000 86,200 48,600 179,200 Future production and development costs (b) 20,300 2,300 35,600 18,400 76,600 Future taxation (c).................... 4,700 2,300 15,500 12,600 35,100 -------- -------- -------- -------- -------- Future net cash flows.................. 13,400 1,400 35,100 17,600 67,500 10% annual discount (d)................ 4,300 400 19,100 8,700 32,500 -------- -------- -------- -------- -------- Standardized measure of discounted future net cash flows....................... 9,100 1,000 16,000 8,900 35,000 ======== ======== ======== ======== ======== </TABLE> F - 91
BP AMOCO p.l.c. AND SUBSIDIARIES 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, 1999, 1998 and 1997: <TABLE> <CAPTION> Years ended December 31, ------------------------ 1999 1998 1997 ------ ------ ------ ($ million) <S> <C> <C> <C> Sales and transfers of oil and gas produced, net of production costs...................................... (12,600) (6,500) (10,400) Development costs incurred during the year.............. 2,900 4,700 5,100 Extensions, discoveries and improved recovery, less related costs.................................... 6,200 3,200 4,000 Net changes in prices and production costs (e).......... 47,900 (30,900) (34,300) Revisions of previous reserve estimates................. 2,600 -- 1,000 Net change in taxation.................................. (18,000) 10,800 14,000 Future development costs................................ (200) (1,000) (3,000) Net change in purchase and sales of reserves-in-place... (900) (200) (1,000) Addition of 10% annual discount......................... 1,900 3,500 5,400 Other .................................................. -- -- (500) ------ ------ ------ Total change in the standardized measure during the year 29,800 (16,400) (19,700) ====== ====== ====== </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, 1999 the Group's share of the standardized measure of discounted future net cash flows of associated undertakings amounted to $2,420 million ($715 million at December 31, 1998 and $830 million at December 31, 1997). F - 92
BP AMOCO p.l.c. AND SUBSIDIARIES 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) 1999................................... 580 100 804 577 2,061 1998................................... 518 105 841 585 2,049 1997................................... 437 115 869 509 1,930 </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) 1999................................... 1,301 164 2,369 2,233 6,067 1998................................... 1,258 200 2,401 1,949 5,808 1997................................... 1,423 195 2,513 1,727 5,858 </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 170,000 b/d in 1999 (1998, 208,000b/d and 1997, 172,000 b/d). (e) Includes amounts produced for the Group by associated undertakings of 264 mmcf/d in 1999 (1998, 221 mmcf/d and 1997, 113 mmcf/d). F - 93
BP AMOCO p.l.c. AND SUBSIDIARIES 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, 1999. 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, 1999 Oil wells (a) -- gross............... 467 75 14,243 11,821 26,606 -- net................. 219.0 28.0 8,687.2 2,971.2 11,905.4 Gas wells (b) -- gross............... 418 33 14,437 2,131 17,019 -- net................. 189.0 11.4 8,980.7 1,214.5 10,395.6 </TABLE> - ---------- (a) Includes approximately 875 gross (231.5 net) multiple completion wells (more than one formation producing into the same well bore). (b) Includes 1,164 gross (692.7 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 -------- -------- -------- -------- -------- (thousands of acres) <S> <C> <C> <C> <C> <C> AT DECEMBER 31, 1999 Developed --gross.............................. 627 75 12,288 7,290 20,280 --net................................ 304 24 5,303 2,010 7,641 Undeveloped (a) --gross.............................. 5,234 3,391 7,665 109,205 125,495 --net................................ 2,416 1,064 4,078 47,401 54,959 </TABLE> - ---------- (a) Undeveloped acreage includes leases and concessions. F - 94
BP AMOCO p.l.c. AND SUBSIDIARIES 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 -------- -------- -------- -------- -------- <S> <C> <C> <C> <C> <C> 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 1997 Exploratory --productive......................... 2.8 2.5 27.2 42.4 74.9 --dry................................ 5.4 11.5 15.0 13.4 45.3 Development --productive......................... 32.5 4.7 258.8 282.1 578.1 --dry................................ 1.2 -- 14.7 23.2 39.1 </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, 1999. 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, 1999 Exploratory --gross.............................. 1 -- 28 40 69 --net................................ 0.5 -- 17.3 13.7 31.5 Development --gross.............................. 17 4 121 68 210 --net................................ 8.3 1.4 70.5 33.8 114.0 </TABLE> F - 95
SCHEDULE II BP AMOCO p.l.c. AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS <TABLE> <CAPTION> Additions ---------------------- Charged to Charged to Balance at costs and other Transfers/ Balance January 1, expenses accounts(a)DeductionsDecember 31, ---------- ---------- ---------- ---------- ---------- ($ million) <S> <C> <C> <C> <C> <C> 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 ========== ========== ========== ========== ========== 1997 Fixed assets-- Investments (b) 34 -- (1) (8) 25 ========== ========== ========== ========== ========== Doubtful debts (b)............ 159 45 (6) (68) 130 ========== ========== ========== ========== ========== Decommissioning provisions.... 3,153 162 (29) (85) 3,201 ========== ========== ========== ========== ========== </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. S - 1